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GRI-97/0236.1a

Gas Research Institute

Underbalanced Drilling Short Course Manual

Copyright  1997 by Gas Research Institute All Rights Reserved

This work is the property of Gas Research Institute. No part of this work may be used or reproduced without prior written permission from Gas Research Institute, and no part of this work may be transmitted to any other party in any form or by any means, electronic or mechanical, including without limitation, photocopy, recording or input into any information storage or retrieval system without prior written permission of Gas Research Institute. Requests for permission to reproduce any part of the work should be mailed to: Contract and License Management Group Gas Research Institute 8600 West Bryn Mawr Avenue Chicago, Illinois 60631

LEGAL NOTICE This publication was prepared as an account of work sponsored by Gas Research Institute (GRI) and other organizations. Neither GRI, members of GRI, nor any person or organization acting on behalf of either: A. MAKES ANY WARRANTY OR REPRESENTATION, EXPRESS OR IMPLIED WITH RESPECT TO THE ACCURACY, COMPLETENESS, OR USEFULNESS OF THE INFORMATION CONTAINED IN THIS PUBLICATION, THAT THE USE OF ANY INFORMATION, APPARATUS, METHOD, OR PROCESS DISCLOSED IN THIS PUBLICATION MAY NOT INFRINGE PRIVATELY OWNED RIGHTS, OR B. ASSUMES ANY LIABILITY WITH RESPECT TO THE USE, OR FOR DAMAGES RESULTING FROM THE USE OF, ANY INFORMATION, APPARATUS, METHOD, OR PROCESS DISCLOSED IN THIS PUBLICATION.

ii

UNDERBALANCED DRILLING SHORT COURSE MANUAL Table of Contents Page

I.

Introduction A. Why underbalanced drilling B. What is underbalanced drilling C. What makes a good candidate D. What makes a bad candidate

1 1 6 6 7

II.

Assessment of the Prospect A. Screening process B. Acquisition of data C. Suitability of the prospect D. Economic analysis of underbalanced drilling E. Summary

9 9 10 12 12 12

III.

Underbalanced Drilling Techniques A. Dry air drilling B. Nitrogen drilling C. Natural gas drilling D. Mist drilling E. Stable foam drilling F. Stiff foam drilling G. Gasified liquids H. Flow drilling I. Mudcap drilling J. Snub drilling K. Closed systems L. Coiled tubing drilling

13 13 27 31 36 43 52 56 62 67 68 70 74

IV.

Summary of Underbalanced Drilling Techniques A. Hard formations B. Soft formations C. Tables

79 79 79 79

V.

Completions A. Productive zone B. Perforating C. Completion

82 82 83 83

VI.

Safety, Environmental, and Regulatory Issues A. Safety B. Environmental C. Regulatory

85 85 85 85

VII.

Candidate Selection A. Examining the candidate

86 86

VIII. Well Planning A. Choosing the method B. Equipment Specification C. Cost Estimation D. Summary

95 95 99 99 102

IX.

Example UBD Candidate A. Candidate Selection B. Analysis of the candidate C. Equipment Specification D. Cost Estimation E. Underbalanced data analysis

104 104 104 110 111 116

X.

Software

118

Underbalanced Drilling Shortcourse

I.

Page 1

INTRODUCTION

The purpose of this course is to provide an understanding of the process of underbalanced drilling, the tools by which to properly assess potential candidates, and the knowledge to properly design the underbalanced well plan. Legal Definition of Underbalanced Drilling According to the Canadian Energy Resources Conservation Board: “When the hydrostatic head of a drilling fluid is intentionally designed to be lower than the pressure of the formation being drilled, the operation will be considered underbalanced drilling. The hydrostatic head of the drilling fluid may be naturally less than the formation pressure or it can be induced. The induced state may be created by adding natural gas, nitrogen, or air to the liquid phase of the drilling fluid. Whether induced or natural, this may result in an influx of formation fluids which must be circulated from the well and controlled at surface.” Underbalanced drilling has been used in almost every producing area of the world. In North America, 7.4% of all wells drilled in 1994, and 10% in 1995 were drilled underbalanced according to a study performed by Maurer Engineering, Inc. The study projects 25% to 37% of all wells drilled in North America in 2005 will be drilled underbalanced.

A.

WHY UNDERBALANCED DRILLING

The primary reason for underbalanced drilling is to improve the economic viability of a project. In some instances, it may improve the financial justification to make a marginal prospect look more attractive. A variety of factors can reduce the cost of drilling the well or increase the initial production rate and ultimate recovery. Not every well is a candidate for underbalanced drilling. In some cases, distinct disadvantages may exist in trying to execute an underbalanced drilling operation when compared to a simpler conventional overbalanced application. Each potential candidate, therefore, must be carefully screened to validate an underbalanced drilling project. A good candidate can be selected because of mechanical advantages, reservoir or performance related factors, or because of safety concerns. A candidate that has been improperly screened and selected can cost more to drill, result in poorer reservoir performance, and potentially create greater risk for well control. In addition, drilling wells underbalanced to reduce reservoir impairment should be planned through the completion phase to properly maintain the underbalanced scheme into the production phase of the well. Underbalanced drilling has significant potential benefits as wells as certain risks. This course will communicate both the benefits and the risks, including demonstrating the UBD process and the necessary tools to validate candidates. Moreover, this course will convey pertinent knowledge for designing a UBD well plan.

Introduction

Page

2

Underbalanced Drilling Shortcourse

1.

Underbalanced Drilling - Advantages

a)

Increased Penetration Rate

Underbalanced drilling can decrease drilling costs in many cases because of an increase in drilling penetration rate. In some cases, drilling the well underbalanced is only justified by cost savings resulting from the increased penetration rate and associated reduced drilling costs. Since the rate of penetration is controlled by several parameters, the increase is difficult to quantify. Studies identified cases, however, where penetration rates drilling underbalanced were as much as ten times greater than rates with mud in a balanced or overbalanced situation penetrating equivalent formations. b)

Increased Bit Life

Underbalanced drilling is accomplished by using lighter drilling fluids, which by design carry less solids or weighting material. This situation has two positive effects. First, the abrasive nature of the fluid is reduced. Second, rock confinement is reduced by the underbalanced condition, thereby reducing the work required to drill away a volume of rock. These two factors can greatly increase the run life of the bit. A secondary benefit realized from the extended bit life is reduced trip time, and hence, reduced drilling costs. c)

Minimized Hole Problems •

Lost Circulation: Lost circulation can be a problem when drilling formations which are highly permeable, fractured, or under pressured as would be found in infill drilling in mature fields. Excessive mud overbalance can also induce reservoir fracturing and cause damage. Damage occurs whenever mud enters the matrix permeability or fracture systems as a result of overbalanced drilling. This can cause plugging, or such a loss of volume that the reservoir is irreparably damaged. In addition, the drilling costs are higher for replacing lost drilling mud. Moreover, lost circulation may also result in increased rig time associated with combating the lost circulation. In the case of underbalanced drilling there is no force driving the mud into the formation. Hence, underbalanced drilling effectively reduces or eliminates lost circulation problems, although lost circulation may still occur if the hydrostatic in the wellbore exceeds the formation pressure. A lightened hydrostatic column does not eliminate the possibility of lost circulation in the case of a severely depleted zone.

•

Differential Sticking: Differential sticking occurs when the drill string becomes embedded in the filter cake and the pressure differential between the wellbore and the fluid in the filter cake can act over such a large area that the axial force required to move the string is greater than the tensile strength of the pipe. The filter cake is formed as a result of the pressure differential between the wellbore and the formation. This force acts to drive the fluid from the mud leaving the solids at the formation face. In the case of underbalanced drilling, the filter cake and the positive pressure exerted by the drilling fluid are eliminated, thus removing the forces that cause differential sticking.

•

Sensitive Shales: Certain underbalanced drilling processes can be advantageous when drilling fluid sensitive or swelling shales. However, drilling certain shales or unconsolidated formations underbalanced may create a hole stability problem. Proper pre-planning and review of geologic and historical drilling information are imperative to a successful underbalanced drilling program.

Introduction

Underbalanced Drilling Shortcourse d)

Page 3

Rig Time and Cost Reduction

Several factors contribute to the overall reduction of rig time and associated costs in a successful underbalanced drilling operation. A good candidate coupled with a properly planned and executed program will result in higher ROP’s, increased bit life, a reduction in drilling fluid cost and less drilling problems. The savings are translated directly to the economic viability of the project. e)

Formation Impairment

Overbalanced drilling may result in reservoir damage for a variety of reasons. Weight material and polymers used in drilling fluid systems as well as drilled solids can act as plugging agents in fractured or highly permeable formations. This material can be difficult or impossible to remove, thereby restricting the flow from the reservoir. Physical migration of clays and insitu fines caused by high leak off velocities can also create blockage in the reservoir. Drilling fluid filtrate may be incompatible with reservoir fluids resulting in the formation of precipitates, scale or emulsion. The introduction of this foreign fluid can also change the wettability of the rock, thereby decreasing the near wellbore permeability. Underbalanced drilling techniques can reduce or eliminate these factors, thereby minimizing the skin effect. The reduction or elimination of a positive skin in the drilling process can eliminate the need for stimulation of the reservoir during the completion phase. Reservoir impairment not only occurs in the drilling phase, but is also carried through into the completion phase. Therefore, the project should be designed so that the underbalanced program is maintained in both drilling and production phases. f)

Earlier Production

When underbalanced drilling techniques are used, the production from the well begins when the productive zone is drilled. Proper design of surface drilling facilities will allow the operator to contain and separate the reservoir fluids at the surface and begin to sell the product while drilling continues. On the other hand, although a gaseous phase may be produced, this stream may contain levels of H2S, CO2, or N2 unacceptable to the pipeline. There are cases where the value of liquid hydrocarbons produced during drilling operations has offset the drilling costs. Depending on operating costs, 20 to 150 BOPD during drilling will pay the costs. g)

Continuous Formation Evaluation

Underbalanced drilling allows continuous testing of the potential productive horizons while drilling. In some cases, overbalanced drilling methods have masked reservoirs, which later have been found to contain commercial quantities of hydrocarbons. When drilled overbalanced, samples may be flushed and/or gas shows can be masked. Drilled formation samples are transported to the surface in underbalanced drilling operations with less damage or contamination normally caused by drilling fluids used in an overbalanced condition. In 1986, a gas field in Louisiana was discovered that had been drilled through almost 100 times without being recognized. The oil zone had been drilled with 9.2 ppg mud and the gas zone was fully invaded before logs were run. The logs showed a “water zone” in every well. This was discovered during abandonment of the oil field when some temporarily abandoned wells exhibited high gas potential from a depleted, low GOR oil sand.

Introduction

Page

h)

4

Underbalanced Drilling Shortcourse

Increased Producing Rate/Higher Ultimate Recovery

Underbalanced drilling reduces formation damage which yields higher initial producing rates than equivalent wells drilled overbalanced. Higher initial producing rates result in greater early recovery, which have a positive effect on financial return as well as increase the life and ultimate recovery from the reservoir. Greater early recovery means faster payout and a greater rate of return, and possibly a greater total return on investment. i)

Environmental and Cleanup Aspects

Environmental and cleanup aspects of underbalanced drilling need to be considered in the design of the system. On one hand, utilizing air, mist, or foam reduces the liquid requirements thereby reducing the environmental cleanup requirements and potential liability. The chemicals used for foam generation are fairly benign. On the other hand, formation fluids produced during underbalanced drilling can cause additional environmental concerns. In addition to brines and hydrocarbons, the operator may have to contend with H2S and other dangerous gases. A review of local environmental regulations as well as existing geologic and reservoir data are important in the planning and design phase of any underbalanced program. j)

Improved Safety - Safe Drilling Through Depleted Zones

Uncontrolled losses into a fracture system in an under pressured zone can evacuate the annulus quickly, which could induce well kicks from another zone and create an uncontrollable situation in the form of a kick and/or underground blowout.

2.

Underbalanced Drilling - Disadvantages

Not every prospect is a candidate for underbalanced drilling. There are factors which can become an advantage or disadvantage, depending on the aspects of the project. A potential candidate should be screened carefully and the advantages weighed against the disadvantages to properly assess the viability of the project. a)

Increased Drilling Equipment Cost

Although an increase in the rate of penetration can be achieved, an underbalanced drilling project will require specialized equipment not normally found on a conventional drilling project. This equipment will include some combination of rotating BOP’s and surface control equipment, air compressors, nitrogen equipment, separation equipment and downhole tools which are specific to underbalanced drilling technology. The additional equipment costs will be offset by the reduced drilling fluid and rig time costs in some proportion, depending on the project. b)

Wellbore Instability

In some cases, incompetent shales and/or unconsolidated sands are encountered while drilling a well. Hydrostatic pressure is sometimes required to support these sections. Underbalanced drilling techniques could be detrimental to the completion of the project by causing a wellbore stability problem. The result may be the loss of the wellbore. A thorough understanding of the geologic and reservoir conditions, as well as previous drilling in the area is imperative to the proper assessment of an underbalanced drilling candidate.

Introduction

Underbalanced Drilling Shortcourse c)

Page 5

Maintaining Continuous Underbalanced Conditions

There are several reasons why an underbalanced condition may be lost during drilling operations. These include pipe connections, kill jobs prior to trips, periodic kill jobs to conduct conventional mud pulsed logging programs or geosteering, and localized depletion effects. d)

Limitations of MWD & Geosteering Tools

In past underbalanced drilling prospects, one major drawback was the inability to use mud pulsed MWD or geosteering tools. Although electronic telemetry tools and wet connect tools are available, there are still depth and temperature limitations to EM MWD and reliability concerns with wet connect systems. e)

Potential Formation Damage

Since there is not a filter cake buildup in an underbalanced drilling operation, if the formation is exposed to periodic pulses of overbalance pressure, very rapid and severe invasion of filtrate and associated solids may occur. When this occurs, damage to the reservoir may be more severe than a well drilled in an overbalanced condition. Additionally, poorly planned and executed underbalanced programs can lead to formation damage if proper research has not been done to determine bottom hole pressure, permeability, and associated reservoir parameters of the target zone. f)

Spontaneous Imbibition

Due to adverse capillary pressure relations, it is possible to imbibe water based fluids into the formation in the near wellbore area where it may cause a reduction in permeability. This phenomenon is mentioned here; however, in high permeability reservoirs it is not usually a problem and in low permeability reservoirs stimulation is often required regardless of additional damage. For the purpose of this course, this problem is not considered to be a major factor in determining a candidate, and therefore will not be discussed in detail. Further information can be found in the GRI underbalanced drilling manual. g)

Extremely Permeable Zones

Although it is advantageous to choose an underbalanced candidate with high permeability or extensive fracture systems, it may prove to be a disadvantage because of the problem of handling large volume of gas or reservoir fluids on the surface. Should the reservoir have a high deliverability and/or high pressure, well control can become a concern. h)

Proper Well Control

Drilling and completing wells in a flowing condition adds an element of concern regarding safety. High deliverability and high bottom hole pressure are a concern in terms of well control and handling fluid and gas volumes on the surface. Recent developments in rotating blow out preventors and surface control equipment and the increased use of coiled tubing have increased the reliability and comfort level with many underbalanced drilling operations. If high deliverability, poisonous gas, or high bottom hole pressures are anticipated, well control concerns should be weighted heavily in the candidate selection.

Introduction

Page

i)

6

Underbalanced Drilling Shortcourse

Flammability & Corrosion

The use of air as a drilling medium, although economical, can be flammable in certain concentrations and can cause corrosion problems. Flash envelope testing is usually required for each particular reservoir fluid system or gas composition under consideration. Overhead slide depicting the advantages and disadvantages of underbalanced drilling to be used with the above write up

B.

WHAT IS UNDERBALANCED DRILLING

Underbalanced drilling is a technique in which the hydrostatic pressure exerted by the drilling fluid, by design, is less than the formation pressure of any given target. This condition is normally accomplished by using a gas as the drilling fluid, or in combination with a conventional drilling fluid in the form of a commingled system or a foam. The underbalanced condition can also be created by using a light fluid such as fresh water or hydrocarbon to drill reservoirs with higher than a normal pressure gradient. Underbalanced drilling techniques have most often been applied to horizontal drilling programs where the productive interval, the horizontal section, has longer fluid contact time. Even relatively shallow invasion can significantly reduce the productivity of a horizontal well. Generally, underbalanced drilling is achieved by injecting gas into the drill string, thereby reducing the density of the entire circulating system. Special surface equipment is required to control the flow up the annulus and separate the fluid, gas and cuttings on the surface. Other methods such as parasite or concentric strings are sometimes used to inject gas which allow continuous underbalanced conditions to be achieved in a more efficient fashion.

C.

WHAT MAKES A GOOD CANDIDATE

In any underbalanced drilling project, the expected gains, increased production rates and reserves, and decreased rig time and drilling problems, must outweigh the expected increase of certain drilling costs. Each situation must be evaluated individually. There are two main criteria for deciding whether to implement underbalanced drilling technology in a given situation. They are (1) determining if underbalanced drilling offers significant technical or economic advantage compared to traditional overbalanced drilling methods, and (2) determining if there is an expected increase in value that justifies any associated risk. a)

Naturally Fractured Reservoirs

Mud damage of naturally fractured reservoirs from conventional overbalanced drilling can cause a reduction in producing rates. Fracture systems can be plugged with drilling solids or weighting material in an overbalanced situation. Underbalanced drilling eliminates the plugging problem and associated lost circulation. b)

Underpressured Reservoirs

One application for underbalanced drilling is to drill into or through underpressured reservoirs. Without underbalanced drilling, many prospects could not be drilled due to the lost circulation and associated hole problems. The situation becomes even more problematic when drilling through a depleted zone into a higher pressure zone. In this case, underbalanced drilling may be the only practical way to drill the prospect.

Introduction

Underbalanced Drilling Shortcourse c)

Page 7

Horizontal Wells

Many of the underbalanced candidates to date have been in horizontal fractured carbonates. Multiple fracture networks can be intersected through horizontal drilling, and underbalanced drilling techniques can keep formation impairment to a minimum. Filtrate invasion in reservoirs with sensitive clays can be detrimental due to the period of time the reservoir is exposed to drilling fluids during the horizontal drilling phase. Underbalanced drilling can eliminate the filtrate invasion. d)

Oil & Gas Storage Wells/Disposal Wells

These wells rely on high input/withdrawal rates to be effective. Underbalanced drilling can help minimize formation impairment. e)

Workovers

As pressure in a producing reservoir depletes, workover operations create a potential damage potential by using workover fluids. In this situation, the fluid recovery after the workover can be slow. Damage to the reservoir is a possibility, and reserves could be lost. Using underbalanced techniques for workover operations can help speed up fluid recovery and prevent the potential loss of reserves.

D.

WHAT MAKES A BAD CANDIDATE

a)

High Pressure/High Permeability Formations

Although high permeability reservoirs are desirable candidates from a formation impairment standpoint, when coupled with high pressure, negative factors can result. High pressure and permeability equate to high deliverability that may exceed surface equipment handling capacity. This situation presents well control and safety concerns. b)

Swelling Formations/Hole Instability

Candidates where sloughing or swelling shales are suspected, or unconsolidated formations will be encountered, may not be good candidates for underbalanced drilling due to the potential for loss of hole. c)

Macrofractured or Vugular Formation Invasion

In formations that exhibit macroporosity, gravity driven invasion of circulating fluids and solids can occur on the lower side of a horizontal wellbore. In the case of low underbalanced pressures or large porosity features, irreparable damage may occur. d)

Shallow Wells

In shallow wells there may be no improvement in drilling speed or formation damage, and no subsequent cost advantage to UB drilling.

Introduction

Page

e)

8

Underbalanced Drilling Shortcourse

Alternating Productive Zones

Wells with alternating high and low pressure productive zones may have a high potential for underground blowout if drilled underbalanced. These wells may require OB drilling to protect reserves and improve safety.

Introduction

Underbalanced Drilling Shortcourse

II.

Page 9

ASSESSMENT OF THE PROSPECT

Assessment of a prospect is the process used to determine if a well is suitable for underbalanced drilling. The process will be covered in detail later in the manual. This introduction to the process will help facilitate understanding as each method is studied and the requirements for each discussed.

A.

SCREENING PROCESS

SCREENING PROCESS Screening wells can be a time consuming process and should be approached from a negative view point. Make every attempt to discover a reason the well cannot be drilled UB. To avoid investing time and money in the wrong prospect, eliminating poor candidates early should be the goal. There are three underbalanced drilling options for a well and any of the three may be the best choice: •

Upper hole section(s) only,

•

Production hole section only,

•

Entire well.

The screening process consists of the following steps: Step 1 - Data Gathering The first step in data acquisition is to gather pre-existing geologic, drilling, and reservoir data. This will include all information known about the lithology, reservoir, and fluids as well as historical drilling records and production data. Acquire as much current data as possible, including details such as present bottom hole pressure, reservoir fluid/drilling fluid compatibility, and rock/drilling fluid compatibility. Step 2 - Review of Data, Screening of Candidate A quick look technique should be applied to eliminate unsuitable candidates before much time and money is invested in underbalanced drilling designs and engineering. •

Will the well produce more if it is drilled underbalanced?

•

Will it drill faster?

•

Are there overriding concerns about safety or environmental issues that might eliminate economics as a deciding factor?

If the answer to all of these questions is no, then the well can be designed for overbalanced drilling. If any answer is yes, then a quick pressure analysis should be performed to decide whether gas based or fluid based drilling is appropriate. Step 3 - Economic Analysis After determining that the candidate fits the criteria from a macroscopic reservoir and mechanical standpoint, the economic viability of the project should be reviewed to be sure there is an economic advantage to underbalanced drilling. This step should include a review of overall operational costs, production/recovery economics, and safety/environmental aspects. This process will be followed by a comparison of the economic viability of drilling the well underbalanced as opposed to a more conventional overbalanced drilling plan.

Project Assessment

Page

10

Underbalanced Drilling Shortcourse

Step 4 - Technical Analysis If the economics indicate that the well should be drilled underbalanced, a team should review the data to determine if the prospect meets the technical criteria to drill underbalanced. This should be an in-depth review to ensure that it is technically feasible to drill the well underbalanced and to make a final decision on which method(s) will be applied. If this step does not eliminate the well as a candidate, the engineering and planning should start. It is important to consider all aspects, both good and bad, when planning the underbalanced drilling project. A multidisciplined team of professionals including drilling, reservoir and production engineers, geologists, geophysicists, underbalanced drilling professionals, regulatory and safety experts, and other specialized professionals should be consulted in the design and planning of the project.

B.

ACQUISITION OF DATA

Compiling as much data as possible is important to the candidate screening process. The following is a combination of data needed for drilling all hole sections. The data list has been divided into two sections to separate the upper hole sections from the productive interval. This will facilitate analysis by hole section. In cases where the goal is increased ROP to the production zone, and standard drilling through the production zone, the productive interval information will not be required. The data list for the production hole section is in addition to the first data set. All data in the lists is not required to design an underbalanced drilling program. However, more data will allow better engineering up front and start the program further along the learning curve. a)

Data for the Upper Hole Sections

1.

Hole Section Properties

2.

3.

•

Pore Pressure Plot for the Interval

•

Pressure Variations (Charged or Depleted Zones)

•

Presence of Lost Circulation Zones

•

Location of Water Zones

•

Productivity of Water Zones

Rock Properties •

Formation Strengths (Gradient Plot of Minimum Allowable Pressure)

•

Water Sensitive Shale Sections

•

Erosion Potentials

Influx Fluid/Drilling Fluid Compatibility •

Emulsion Potential

•

Scale Potential

•

Corrosion Potential

•

Contamination of Circulating Fluid by influx

Project Assessment

Underbalanced Drilling Shortcourse 4.

Rock/Drilling Fluid Compatibility •

Potential Reaction with Clays and Shales

•

Formation Dissolution

•

Reactivity and Transport of Cuttings.

b)

Additional Data for the Producing Interval Hole Section

1.

Reservoir Properties

2.

3.

4.

•

Current Target Reservoir Pressure

•

Presence and Pressure of Multiple Zones

•

Pressure Variation within the Reservoir(s)

•

Location of Oil, Gas, and Water contacts

•

Presence of Sealing/Nonsealing Faults

Rock Properties •

Reservoir Lithology

•

Vertical and Horizontal Permeability

•

Porosity

•

Pore Size and Pore Throat Distribution

•

Presence of Faults, Fractures, Vugs etc.

•

Formation Strengths

•

Initial Saturations

•

Capillary Pressure Characteristics

•

Wetability

•

Relative Permeabilities

•

Glazing Potential

Reservoir Fluid Properties •

Compositions

•

Asphaltine/Paraffin Contents

•

Cloud and Pour Points

•

Viscosities and Densities (Downhole and Surface)

•

Bubble Point and PVT properties

•

Dew Point and CVD properties of Rich Gases

•

Presence of H2S or other Hazardous Components.

Reservoir Fluid/Drilling Fluid Compatibility •

Emulsion Potential

Project Assessment

Page 11

Page

5.

C.

D.

E.

12

Underbalanced Drilling Shortcourse

•

Hydrate Potential

•

Scale Potential

•

Precipitation or Asphalt Deposition Potential

•

Gas Entrainment Characteristics

•

Explosion Potential

•

Corrosion Potential

•

Degradation of Base Fluid by Formation Fluids

Reservoir/Drilling Fluid Compatibility •

Potential Reaction with Clays

•

Potential Reaction with Hydratable Shales

•

Formation Dissolution

•

Countercurrent Imbibition Potential

•

Reactivity and Transport of Cuttings.

SUITABILITY OF THE PROSPECT •

Increased ROP

•

Increased Production/EUR

•

Overriding Safety/Environmental Concerns

ECONOMIC ANALYSIS OF UNDERBALANCED DRILLING •

Enhanced Production Rates and Recovery

•

Time comparison

•

Economic analysis

SUMMARY

The first step in underbalanced drilling is data gathering. This is followed by reviewing the data to determine if the well is a viable candidate for UB drilling, deciding which method is appropriate, and designing a program to drill the well. This subject will be covered in depth in section VII “Candidate Selection” and Section VIII “ Well Planning.” .

Project Assessment

Underbalanced Drilling Shortcourse

III.

Page 13

UNDERBALANCED DRILLING TECHNIQUES

This section furnishes an overview of the different underbalanced drilling techniques. The primary function of the circulating medium in underbalanced drilling is to lift cuttings from the hole. Hole cleaning requirements for each technique will be reviewed. Refer to the GRI Underbalanced Drilling Manual for a more detailed look at hole cleaning and circulating pressures. Each method of underbalanced drilling requires unique surface, bottom hole, and return systems. This chapter will analyze the equipment selection for the different underbalanced drilling methods, along with a review of the operational procedures associated with that type of drilling. Limitations of the various techniques are discussed and a comparison of the advantages and disadvantages is presented in the individual underbalanced drilling technique sections. In conclusion, a discussion of the individual design criteria will be provided.

A.

DRY AIR DRILLING

The use of air as a circulating fluid in rotary drilling applications has been around since the early 1950’s. Economical and environmental interests have promoted the growth of dry air drilling. Cost savings have been realized through greater ROP, less rig time, and longer bit life. This method of drilling is environmentally friendly, since drilling mud is not necessary. The air circulation is maintained by use of compressors and boosters on the surface. The air lifts the cuttings from the wellbore by exerting a drag force upwards that is greater than the gravitational force downwards.

1.

Equipment Selection

a)

Surface Equipment

Air Compression System The air compression system is usually a combination of one or more compressors and a booster unit. Other associated surface equipment is considered vital to the air compression system. A typical layout of an air compression system, used in conjunction with dry air drilling, is shown in Figure 3-1. The major components are discussed below. Compressors These are units capable of taking ambient air and compressing it to a pressure that allows it to circulate the well. The types of compressor units available are - rotary vane, straight-lobe, reciprocating, and rotary screw. The reciprocating and rotary screw type are more often used for drilling applications than any other type of compressor units. Compressor selection can be controlled by local availability. The air compressing unit is powered by a diesel engine. Whenever rig-site noise levels are a concern, a specially silenced compressor is available. These types of units are designed to meet EPA noise restrictions for industrial compressors, which is 76 dB at 22 feet. These quieter units are also capable of delivering the rates and operating pressures necessary for most oil and gas drilling applications.

Underbalance Drilling Techniques - Air Drilling

Page

14

Underbalanced Drilling Shortcourse

Compressors provide low-pressure air, from 100 to 300 psig, directly for drilling or, when necessary, to charge boosters. The compressors take atmospheric air at a precise rate, compress it to a specified pressure, or the limit of the unit, and convey the compressed air downhole via the standpipe. Additional compressors can be added in parallel if a larger volumetric flow rate is necessary. Refer to the GRI Underbalanced Drilling manual for a more detailed look at compressors.

Mist Water Unit

Booster

Compressors

Foamer Pump

To Kelly Hose

Valve Manifold

Bleed-Off Line

To Primary Jet

To Secondary Jet

Stand Pipe

Optional

Air Header

Flow Meter

High Pressure Vent Line Blow-Down Line

Figure 3-1. An air compression system layout, for dry air drilling. Boosters A booster is a positive displacement compressor that provides high-pressure air, from 600 to 1,500 psig. It receives the volumetric air flow from the compressor(s) and boosts the pressure. Normally a single booster unit has an adequate volume capacity for most air drilling operations. If one booster cannot handle the pressure output from several compressors, additional booster(s) can be added in parallel to the system. Air Header and Valves The discharge line between the compressed air section and the standpipe needs to be of sufficient diameter to minimize friction losses, which is usually 4 inches. The pressure rating of this line should meet or exceed the discharge pressure of the compressed air section. A check valve should be installed in the line immediately downstream of the discharge to prevent any backflow of air or fluid to the compressor(s) or booster(s). A valve manifold, sometimes termed the air header, is located upstream of the standpipe. The air header should be connected to the blooey line, which is the air return line to the pit, via a blowdown line. This will allow making connections without taking the compressors off-line or shutting them down. A valve system should be located on the rig floor so that control of the air flow is maintained at the driller's console. In the manifolding, a valve to the standpipe from the mud pumps should be provided. This allows using the mud pumps if necessary without the air system.

Underbalance Drilling Techniques - Air Drilling

Underbalanced Drilling Shortcourse

Page 15

Bypass Blowdown The main air header is connected to the high pressure vent line, through a bypass and choke. A muffler, referred to as a blowdown silencer or bypass muffler, is connected to this line. The purpose of the muffler is to silence the discharge air when it is necessary to blow down the system for a connection or shutdown. A silent shutdown is accomplished by opening the bypass to the muffler and closing the main air header downstream of the high pressure vent line. Mist and Soap Pumps Mist and Soap pumps are not necessary for dry air drilling. However, it is recommended that they be a standard part of the surface equipment. Water influx can occur during the drilling operations. If this happens, these pumps make it possible to switch to mist or foam drilling to control the water influx, which is discussed in more detail in later sections of this manual. These pumps usually have high pressure ratings and small displacements, and are generally not more than 10 hp. The associated tanks seldom have a volume greater than 10 bbls. Scrubber To ensure that a minimum amount of moisture is circulated through the system and to protect the booster(s), a scrubber is used to remove excess water. Solids Injectors The most practical types of solids injectors are the endless chain and the belt-type. This equipment is used to place hole-drying powders in the wellbore, to reduce friction in a deep hole or to dry up any weeping water zones. Bleed-off Line The intention of this line is to bleed-off the pressure within the standpipe, rotary hose, kelly, and the drill pipe down to the top float valve. The bleed-off line should be connected to the blooey line. Kelly In conjunction with dry air drilling, the hexagonal kelly is preferred over the square type kelly because it seals better in the rotating head. b)

Effect of Elevation on Equipment Performance

Atmospheric pressure decreases by approximately 0.5 psi for each 1000 feet of elevation increase. This would correspond to a 3.4% decrease in compressor deliverability per 1000’ elevation at 60°F. Additionally, elevation further impacts compressor deliverability because of its effect on the power output of the compressor’s diesel engine. An additional 3.6% decrease in compressor deliverability, due to the power loss of the diesels, can be attributed to every 1000 ft. elevation increase. The delivery rate is also influenced by temperature to a lesser degree, but should not be considered negligible and is about a 2.1% decrease per 10°F increase. A compressor operating in Denver at 90°F would lose ≈30% due to altitude and ≈10% due to temperature for a total output of ≈60% of rated output when compared to operating at sea level and 60°F. Actual calculated output would be 64%. Refer to Chapter 2 of the GRI Underbalanced Drilling Manual.

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Bottom-hole Equipment

Bits Standard roller cone bits are applicable in air drilling. Sealed bearing bits with the jets removed work well. Heat generated while drilling is the primary problem to consider both for bit selection and bit life. Generally, bit wear is not detectable during air drilling; thus, rotating time is frequently the method used to determine when to pull the bit. Percussive bits are often used and can improve penetration rates and reduce cutting face temperatures because of reduced friction. The drill pipe and BHA’s are often the same as those used in conventional mud drilling. Since buoyancy is negligible, the effective string weight is the string weight in air. Drill String Floats Normally there are two non-return or float valves located in the drill string. These are run in the top and bottom of the string. The lower float valve prevents backflow of cuttings that could plug the bit. The upper float valve retains the high-pressure air in the drill string during connections and is not considered necessary when the standpipe pressures are low. As a minimum, the drill string should have the lower float valve. There are two basic types of float valves, flapper and dart-type. Figure 3-2 illustrates both of the basic types. Typically the lower float valve is the dart-type and the upper float valve is the flapper type. It is common practice to remove the spring from the flapper type valve, so that once the pressure has bled down to the annulus, the flapper will fall open. This allows the running of wireline tools through the string float. Standard drilling floats are held in place by the drillpipe pin and are not appropriate for underbalanced drilling. Specially designed floats that lock into the float sub are required. To relieve the trapped pressure under the floats, a sub is made up that has a pin that screws down and mechanically opens the float. Making up, bleeding, and removal of this sub requires time. The amount of time depends on the volume between floats and the fluid being bled. A fire stop can be added at the lower float. This is an inverted float locked open by a fusible ring. If a downhole fire starts, the fusible ring melts and stops any additional air from exiting the drillstring. This can shorten the duration of a downhole fire and avoid melting the drillstring.

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Figure 3-2. Drillstring float valves for air drilling d)

Return System Equipment

Rotating Kelly Packer The purpose of the rotating kelly packer is to seal the annulus at the top of the bell nipple, or banjo box, and to divert the air and cutting returns into the blooey line or mud flow line. The two types of rotating kelly packers are the Rotating Control Head (RCH) and the Rotating Blowout Preventor (RBOP). RCA's have been used successfully in air drilling for many years but have several inherent problems. The RCH tends to leak at low pressures as it starts to wear; the life of the element cannot be predicted; they are not rated for pressure containment by the manufacturer; and they are not considered a BOP by API. Rotating BOP’s are certified by API as a BOP and are rated by pressure containment. They are hydraulically actuated and the elements can easily be replaced while the drillstring is in the hole. RBOP's are common at 1500 psi working, 3000 psi static, and are now on the market at 2500 psi working, 5000 psi static. It should be noted that the diverter system does not eliminate the need for a conventional BOP stack. Local regulatory requirements must be met. At the very least, the conventional BOP stack should contain pipe rams and blind rams. Blooey Line The purpose of the blooey line is to carry exhaust air/gas and drilling cuttings to the pit. It is recommended that the blooey line be a minimum of 150 ft in length and have a cross-sectional area equal to or greater than the annulus area. The end of the blooey line should extend past the flare pit wall by a minimum of 6 ft and

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should be situated perpendicular to any prevailing wind. The entire length of the blooey line should be anchored securely and grounded. Burn Pit For an air or gas drilling operation, a burn pit should be situated at the end of the blooey line and located at a safe distance from the standard mud drilling reserve pit. This pit will allow the safe burning of any produced gas or drill gas, without any danger of a reserve pit fire near the rig. Regulations do not normally allow liquid hydrocarbons to flow to a pit. Any produced oil will have to be separated and stored. Gas Sniffer A gas sniffer can be utilized to detect small amounts of natural gas entering the return flow from the annulus. The gas sniffer should be situated in the blooey line, immediately downstream of the flow from the annulus. Pilot light At the end of the blooey line, a pilot light should be maintained so that any gas produced while drilling can be ignited. If the drilling fluid is natural gas, the flame should only be ignited when the blooey line has established full flow. Sample Catchers A sample catcher can be installed using a small diameter pipe, 2 inches for instance, on the bottom side of the blooey line. It should be mounted at an angle and open to the return flow from the annulus. A full opening ball valve should be placed on the small diameter pipe to facilitate sampling.

2.

Instrumentation

Normally the instrumentation of the rig is adequate for most air drilling operations. The addition of standard orifice-plate meter runs should be considered for measuring the injection rates and the return rates. This will allow the establishment of known flow rates, essential for high-angle or horizontal drilling operations. It is also recommended that pressure gauges be installed in the low and high pressure lines. These rates and pressures should read out and be recorded at the driller's console. A back pressure gauge should be installed in the mud flow line, if aerated drilling is being conducted. To assist in maintaining the low bit weights normally associated with air drilling, an automatic driller can be used.

3.

Operational Procedures

This section provides some general guidelines on operating procedures during dry air drilling. It should be noted that these are only generalities and will need to be modified to fit individual well conditions. a)

Standpipe Pressure

Monitoring the standpipe pressure carefully while circulating or drilling ahead is extremely important. Large changes in pressure downhole, caused by major hole problems, may show up as only a small change in the standpipe pressure. For this reason, any visible change in standpipe pressure should be treated as an indication of a possible problem downhole. A flow recorder installed on the blooey line or inlet line is often the first indication of bit plugging before the pressure increase is seen on the standpipe. The cause of the pressure and return rate variations should be determined, and if necessary, appropriate changes made.

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Making Connections

In dry air drilling operations, connections tend to be a bit more complicated than when drilling with conventional mud systems. Unlike conventional mud, air is a compressible fluid, thus a considerable amount of air volume is in the drill string. The pressure must be bled from the drillstring before breaking off the kelly. If not, the stored energy will be violently released when the kelly is broken off, thereby presenting a safety hazard to the entire rig crew. The time involved in making connections during any UB drilling involving gases can be significant and must be included in the rig time analysis. Perform a cost comparison between rotary rigs and top drive rigs before making a decision on which rig is more economic. In some cases, the extra expense of a top drive will be easily recovered by eliminating 2/3 of the slow connections. The pressure can be bled through the air header by first bypassing the compressor flow to the blooey line and isolating it from the drill string. This allows the compressors to stay on line. Next, the valve to the bleed-off line would be opened and the upper drill string, which is above the upper float, the kelly hose, and the standpipe would be bled off. Once the pressure is released, disconnect the kelly and add a joint to the drill string. Once the kelly is reconnected, it is common practice to leave the drill string in the slips until circulation has been re-established. In other words, returns should be observed at the blooey line. If the drillstring is picked up before the cuttings are moving, the cuttings can be tightly packed in the annulus, making it more difficult or impossible to break circulation. The drillstring will be stuck. c)

Tripping

Tripping from an air drilling hole is very similar to tripping with conventional mud filled hole. The one difference is that the operation is much cleaner when using air as the circulating medium. It is standard operating procedure to circulate bottoms up before tripping out. This should only take a few minutes since air drilling annular velocities are considerably higher than those with conventional mud. When the volume of cuttings at the blooey line decreases, the trip can commence. Survey instruments, such as single shots, should not be used with air drilling operations. An instrument of this type would be destroyed when it hit bottom. Surveys should be run on wireline. Normally the rotating head rubber is left in the bowl during tripping operations. This will force any gas flowing from the well to be diverted into the blooey line. If it is known for sure that the well is not making any gas, the rubber can be extracted to extend its life. The rotating head rubber must be removed before pulling the BHA, since the diameter of the BHA is greater than that of the drill string. If gas flow is present, it will be necessary to run the compressors through the primary jet, which is on the blooey line at the end of the blow down line. This will pull the gas down the blooey line by creating a vacuum from the jet, back to the rotating head. This reduces the chances of having natural gas on the rig floor. After the BHA is run back in the hole, the rubber should be placed back into the bowl of the rotating head if gas is present. Then complete the trip to bottom. Start the air flow and observe the returns. If water is present, it must be unloaded from the wellbore and the wellbore dried before resuming dry air drilling operations.

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Unloading the Hole

Water is used to displace the cement when cementing the casing in place. This water is left in the casing until the cement has set up. Before air drilling can resume it is necessary to unload this water from the hole. There are two methods to accomplish this unloading. The first method is to trip into the wellbore to the float collar: •

Circulate water with the mud pumps at low standpipe pressure.

•

Start the compressors and deliver air to the standpipe so that it begins to aerate the water. Be careful to maintain the standpipe pressure below the air pressure and, if necessary, reduce the pump rate.

•

Pump approximately 10 BPH of mist fluid into the air flow with the mist pump. The mist fluid should contain 0.1 to 0.25 percent, by volume, foaming agent , or “soap."

•

When air returns to the surface, reduce the mud pump volume and increase the air volume. The mud pumps can be turned off after the standpipe pressure decreases.

The second method unloads the hole without using mud pumps, called staging into the hole: •

The string is tripped part-way into the wellbore. A float valve is installed in the drill string near the bit so water cannot enter the string as it is tripped downhole. As a result, the water will be displaced up the annulus. This increases both the hydrostatic head and the bottomhole pressure.

•

Connect the kelly and initiate air circulation. The air in the drillstring will be compressed until the air pressure at the float valve is greater than the water pressure below the valve. This will result in lifting the water up the annulus and out the blooey line.

•

When the flow of water has ceased, disconnect the kelly and commence tripping into the wellbore, again only part way.

•

Repeat the second and third steps until the float collar is reached and the casing has been displaced of water.

The staging stop depths are determined in part by the capacity of the air compression system. Obviously, a low-pressure system would not be able to unload as much water as a high-pressure system. Rules of thumb are not more than 2000 ft in any one stage or 2’ per psi available air pressure. Refer to the GRI Underbalanced Drilling Manual for more details on staging depth calculations. Once the hole is unloaded, the float equipment and the shoe are usually drilled out utilizing “Mist Drilling." When the new formation is encountered, the hole should be dried out before commencing dry air drilling. Circulate bottoms up until the mist comes back clean. At this point the mist pumps should be shut down.

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There are two common methods used to displace any remaining water in the well. One is to circulate a slug of stiff foam around wellbore. The other is to circulate dry air, at drilling rates, for a period of time, usually 1/2 hour to 1 hour. The deeper the well the longer the circulating time. If water is still being produced, it is possible that water influx is occurring and the well cannot be dried out. Once water is no longer evident at the blooey line, the well is ready to be dried out. The most economical drying agent is the cuttings. As they travel uphole, moisture will be adsorbed on their surface. It is recommended during this drying process to drill ahead in small intervals, 5 to 10 ft, and circulate bottoms up (CBU) between each interval. After each CBU, reciprocate the string to assure that the pipe will move freely. If movement is hindered, this could be an indication of the formation of mud rings, as described below. In most cases the well should start dusting before 30 ft of new hole has been drilled. If the well is not dusting before 90 ft has been drilled, the well is probably making too much water. If this is deemed to be the problem, dry air drilling is not considered to be a viable option. In this case drilling ahead should be done with mist or foam. In general, the total time necessary to dry the hole should not exceed six hours. e)

Water Inflows While Drilling

Water inflow occurs when a water bearing formation or fracture system is penetrated. The water is broken into droplets as it enters the wellbore and then lifted from the hole along with the cuttings. If the water inflow is small, the adsorption potential of the cuttings can effectively remove the water and dry the well. When a modest inflow of water occurs, there is a flow regime where moistened cuttings tend to build up into a mud ring. The danger of this build up is the possibility of sticking the drill string and increasing the chances of a downhole fire. Higher inflows of water will saturate the cuttings and reduce their tendency to form a mud ring. At this point, water droplets can be observed at the blooey line, in the returns. If the water inflow is great enough, the air flow will not be capable of breaking the water into droplets; therefore, the water will circulate in slugs. These slugs can cause wellbore instability and create problems at the surface. During water slugging, the standpipe pressure can increase by 50 psi or more. Water inflows can be detected at the surface. The density of the air/water/cuttings returns will increase, thus increasing the standpipe pressure. Also, the formation of a mud ring will increase frictional pressure losses and increase standpipe pressure. An increase in the standpipe pressure of only 5-10 psi can accompany an inflow with the potential to form mud rings. One of the first indications that a small water inflow is occurring downhole is that the well will stop dusting; that is, materials discharge will cease. Many surface layouts include a deduster at the blooey line, so the cessation of dusting is not always visible from the rig floor. The sample catcher should be checked frequently to ascertain that cuttings are continuing to circulate out. Note that an increase in standpipe pressure does not always indicate the formation of a mud ring, although any time the pressure of the standpipe increases should be a warning of a potential problem. When a pressure increase is observed, stop drilling and check the sample catcher and the blooey line to determine if cuttings are returning. Also, check the return flow rate and reciprocate the pipe to determine if sticking is occurring.

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String Washouts

Washouts are not common in dry air drilling, but do occur. The washout can result because of a fatigue crack in the pipe or tool joint or because of a poor seal at the threaded connection. The result is that air will escape through the washout into the annulus and not through the bit. The returns are laden with solid cuttings moving at a high velocity. These cuttings cause erosion on the lower side of the tool joints. Additional wear on the tool joints is caused by the rotating contact of the drill string with the non-lubricated wellbore, whereas conventional mud provides lubrication. Both of these processes reduce the wall thickness at the tool joint, where bending stresses are highest. Downhole vibrations are greater in dry air drilling operations than in conventional mud operations, allowing fatigue cracks to more readily initiate and propagate. Washouts due to a poor seal at the threaded joints tend to propagate much slower in dry air drilling, since the leaking medium does not contain any solids. When a washout occurs, the standpipe pressure will decrease, regardless of the mud system used, although with a conventional mud system, the washout is much easier to locate than when using air as the circulating medium. When using mud, the string is simply pulled wet and the fluid will leak through the washout and is visually located. In air drilling operations the string must be tripped to surface and smaller jets installed in the bit. The bottomhole collar is then connected to the kelly and while circulating at drilling rates, the standpipe pressure is recorded. Then begin tripping in the hole and periodically, every 4-5 stands, attach the kelly, circulate at drilling rates, and observe the standpipe pressure. When a reduction in standpipe pressure is noted, the washout will be in the last section of pipe run in the hole. Now pull one stand at a time, connect the kelly, circulate at drilling rates, and observe the pressure. When the pressure increases to the normal observed pressure, the washout will be in the last stand pulled. This process is extremely labor intensive, but necessary. Never be tempted to drill ahead until the string parts and then fish for the parted section. The danger behind this strategy is the string parting during tripping. Since the wellbore has no buoyancy, the fish will fall very rapidly and can create a corkscrew fish, which in most cases is impossible to retrieve. If the washout is significant enough that it is believed that the string could part during tripping, the following procedure is recommended:

4.

•

Set the bit on bottom.

•

Locate the washout by reverse circulating air and running a wireline spinner tool inside the string.

•

Adjust the neutral point and back off the string below the washout, leaving a fish that is readily retrievable.

Limitations Of Dry Air Drilling

There are several limitations of dry air drilling. The main limitations are water inflows, downhole fires, and wellbore instability. Other limitations would include higher friction between the drillstring and the wellbore, the operation of mud motors/MWD systems, and the encounter with sour gas. a)

Water Inflows

As previously discussed, the flow of water into a well drilled with dry air can cause serious problems. If the influx of water is large enough, it could preclude the use of dry air as a drilling medium.

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There are several methods currently used to shut-off water inflow. A few of these methods include: cement squeeze, resin-catalyst squeeze, the use of gases that will mix and form precipitates, and the use of a gas that will react with formation waters and form precipitates. All of these methods require the setting of a single packer above the zone of treatment, if the zone is close to the hole bottom, or the setting of a straddle packer across the zone. Either case requires knowing precisely where the water flow is originating from. Acquiring this vital information may require wireline logging. The treatments all take time, especially the resincatalyst type. Using any of these methods to stop the water inflow would only be worth considering if there is still a substantial amount of hole to be drilled with air. The usual solution to water inflow is to change the drilling medium to mist or foam. The produced water from this solution, however, still has to be disposed of properly at the surface. The disposal costs for the produced water may outweigh the costs to complete the drilling with conventional mud systems, thus underbalanced drilling would no longer be economical. b)

Downhole Fires

The feasibility of a downhole fire occurring during dry air drilling is a potential limitation. When a mixture of oil/gas and air, with a high enough concentration of hydrocarbons, is exposed to an ignition source, a fire can occur. At atmospheric pressure, a concentration of 5-15% natural gas is combustible. The upper limit climbs with increasing pressure. For example, a concentration of 30% hydrocarbons is combustible at 300 psi. The influence of pressure on the combustible regime for a typical natural gas is shown in Figure 3-3.

450 400

Pressure (psia)

350

Inflammable Area

300 250 200 150 100 50 0 0

10

20

30

40

Natural Gas in Mixture (% by Volume)

Figure 3-3. Effect of pressure on combustible concentrations of natural gas in air (after US Bureau of Mines Report of Investigations 3798). Most downhole fires occur after the formation of a mud ring. Downhole fires do not occur when dry gas is encountered while drilling with dry air. Some liquid has to be present. The role of the liquid in causing a fire is presumably to moisten the cuttings, thereby permitting the formation of the mud ring. Once the mud ring has formed, the air pressure will increase rapidly to the set limit or the delivery pressure limit of the compressor system. The temperature of the gas below the mud ring will increase as the pressure increases. Since air flow has stopped, any amount of hydrocarbon inflow will rapidly lead to combustible mixtures. When the gas mixture has entered the combustible regime, the heating due to compression can

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ignite the mixture. Or, sparking caused by the drillstring rubbing the borehole wall can ignite the gas mixture. A pinhole in the drillstring, where frictional heating of the string by the air flow may be significant, has also been cited as a potential source of ignition. Since downhole fires very rarely reach the surface, detecting one can be difficult. It may be necessary to run a wireline temperature survey to obtain confirmation that a downhole fire has occurred. Often the drillstring will melt where the combustion has taken place. If this occurs, the fish is difficult to retrieve, and may require a sidetrack. The most obvious ways to avoid downhole fires are to prevent the formation of combustible mixtures and to remove any ignition sources. Using natural gas or an inert gas would prevent the formation of combustible mixtures, but may not be economically feasible. The prevention of mud ring formation is an extremely effective method of avoiding downhole fires. Probably the most commonly used method of preventing downhole fires is mist drilling when natural gas is encountered. If it is believed that gas has been encountered or a mud ring has formed, the following is the recommended operating procedure:

c)

•

Stop drilling.

•

Shut off the air and monitor the gas flare at the pit. If the flare continues to burn, any of the following indicates that the gas is wet: wet cuttings, black smoke, yellow smoke, or sparking at the blooey line exit. The last three indicate that condensate is present.

•

If the flare does not continue to burn with the air shut off, resume air circulation and determine if the gas is wet, using the indicators described above.

•

If the gas is wet, switch to mist or natural gas drilling.

•

If the gas is dry, drill ahead in five to ten foot intervals, reciprocating the string between intervals. Continue to do this until it is certain that there is no further possibility for encountering wet gas.

Wellbore Instability

Wellbores tend to become less stable with decreasing wellbore pressure. Low wellbore pressures, especially in weak formations, lead to mechanically induced instability. Also, a significant water inflow, when there are water-sensitive shales exposed uphole, can contribute to wellbore instability. Dry air drilling exerts the lowest wellbore pressures and thus one of the highest incidents of wellbore instability. Sometimes during dry air drilling, large rock fragments break away or slough from the borehole wall. The terminal velocity of these larger fragments can be much higher than the velocity of the dry air medium. In this case the fragments will not be lifted from the well by the air circulation. Those fragments not lifted from the hole will be broken down by the grinding action of the bit, until the fragments are small enough to be lifted by the air circulation. If the sloughing rate exceeds the rate at which the bit can reduce the fragments to the required lifting size, the fragments will accumulate to the point where the string will eventually become stuck.

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The sloughing and grinding process increases the number of rock fragments in the air flowing up the annulus, which in turn reduces the annular velocity and hole cleaning capabilities. Additionally, the wellbore diameter increases because of the rock sloughing, thus reducing the annular velocity and further degrading hole cleaning abilities. If the formation sloughs too fast, air drilling must be terminated. It is unlikely that increasing the circulation rate can adequately lift enough of the fragments from the borehole to forestall the annulus from eventually packing off. Furthermore, a higher circulation rate will tend to increase the rate at which rock fragments are dislodged from the borehole wall. A drilling fluid with greater lifting capacity and higher wellbore pressures must be used. d)

Operating MWD Systems With Compressible Drilling Fluids

When drilling a highly deviated hole or horizontal section, steerable motors and real-time directional equipment are necessary to stay on a projected path. Downhole motors and Measurement-While-Drilling (MWD) systems were designed to operate in a non-compressible fluid. Information is sent to the surface, real-time, by sending pulses to surface equipment through the non-compressible circulating medium. Since air is a compressible fluid, this type of equipment will not operate properly. There are Electro-Magnetic (EM) MWD systems available for use with compressible fluids. This type of equipment operates by sending out an electrical signal to a receiver at the surface. However, formation resistivity and depths greater than 5000 ft. can cause inadequate signal transmission. The other option available is use of wet connect wireline. This technology is improving and does not have the same disadvantages as EM MWD. One of the two systems should be able to provide data. e)

Air Motors

The air volume necessary for proper hole cleaning is three times greater than the recommended flow rates for a conventional mud motor. If a downhole motor is necessary, an air motor is recommended. Even with the higher flow rates required for hole cleaning in a dry air drilling process, the bit speed is kept low. With air motors, low differential pressure is all that is required to provide ample torque for drilling. The air drilling motor offers several advantages over conventional mud motors, such as: the motor does not stall easily, additional boosters are not required, efficiency is improved, the motor does not overspeed when lifted off bottom, and the air motor is suitable for both compressible and non-compressible fluids. f)

Sour Gas

Air drilling is a poor choice when there is a possibility of encountering sour gas. Anytime sour gas is anticipated, a closed system is the safest underbalanced drilling technique to use in containing the gas, but never in conjunction with dry air drilling due to the explosive mixtures with produced hydrocarbons. Gas alarm systems, escape equipment, and properly trained personnel are recommended for possible encounters with sour gas. g) Torque and Drag Torque and drag is higher for an air system than a mud system. The friction coefficient for mud drilling is typically 0.75, and for air drilling is 0.2 to 0.35, causing 2 - 4 times as much friction. This can limit the achievable horizontal section that can be drilled.

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Reverse Circulation Air Drilling

Some of the problems described in this section on conventional air drilling may be overcome or mitigated by reversing the air circulation. In this procedure, air is injected down the annulus and returned with cuttings up the drillstem. This procedure, still considered experimental, has several important advantages indicated from tests by Graham, 1986, under a GRI contract. •

Reduced Damage to Permeable Formations - Tests strongly suggest less damage to the formation than with conventional air drilling. Conventional air drilling, in turn, normally results in less damage than conventional mud drilling.

•

Quality and Size of Drill Cuttings Improved - Drill cuttings are larger and have less contamination. With the larger samples, it is possible to run quantitative petrophysical analysis which is virtually impossible with conventional “dusting."

•

Wellbore Integrity Improved - The potential for reduced wellbore damage would result from less erosion of the hole wall by cuttings or water influx that could promote uphole sloughing of sensitive shale.

•

Less Air Volume Required - Tests indicate that reverse drilling uses less air volume. This is expected since the velocity of air in the larger annular space would no longer be critical to cuttings removal.

•

Less Influx - This is due to higher annulus back pressures.

•

Limitations - There is a greater likelihood of cuttings plugging the bit. Overall ROP is reduced due to long blowdown times on connections (This can be mitigated by the use of a top drive). Surface equipment design needs improvement. Large inflows at the bit may cause problems in circulating down the annulus.

6.

Summary

a)

Advantages

The advantages of dry air drilling, in comparison with conventional mud drilling, are witnessed in several areas. Substantial increases in ROP when drilling through hard rock formations reduces the amount of rig time required and results in fewer bits being used. Some well bore problems, such as sloughing of sensitive shales, can be eliminated. Also, this type of drilling allows the use of percussion type bits which can further improve ROP’s and allow early detection of hydrocarbons because of larger cuttings. As in any underbalanced drilling technique, the fluids and solids invasion into the producing formation(s) can be prevented. This can eliminate costly stimulations necessary to remove formation damage induced by typical overbalanced drilling techniques. Likewise, if a fractured system is encountered, loss circulation can be minimized or eliminated. Another advantage to dry air drilling is uncontaminated cuttings, allowing ready detection of hydrocarbons.

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b)

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Disadvantages

The disadvantages of dry air drilling are water inflows, downhole fires, wellbore instability, limitation of downhole measuring devices, and encounters with sour gas. Water inflows can cause real problems in cuttings removal, stuck pipe, and hole stability. Downhole fires can occur when a hydrocarbon zone is encountered and the concentration of hydrocarbons in the air flow reach combustible levels. This is generally not a danger if the hydrocarbon is a dry gas. On the other hand, if the hydrocarbons are wet or an inflow of water is present, a mud ring can form. This will allow the hydrocarbon concentration to rapidly reach combustible levels. Wellbore stability can become a real problem if formations are encountered where the mechanical stresses are not strong enough to keep the borehole from collapsing. Also, wellbore stability is a problem where water inflow is sufficient to cause sensitive shales to slough. Typical downhole measuring equipment MWD cannot be used. Instead, specialized equipment like EM MWD must be used when necessary. In inhabited areas, noise and dust can create problems. Mechanical silencers and dedusters are available to address this problem. c)

Design Criteria

Underbalanced drilling with dry air should be given consideration when any of the following criteria exist: ·

Drilling in areas with hard rock formations;

·

Areas with known lost circulation problems;

·

Formations that are considered to be damaged easily by drilling fluids;

·

Formations with adequate strength to withstand mechanical stresses without collapsing;

·

Areas with limited ground water flow;

·

No known high pressure formations or sour gas;

·

Areas where the ROP is sensitive to borehole pressure.

Economics should be the deciding factor in most cases. Consider if the cost savings outweigh the cost of extra equipment. Also take into account any environmental considerations that make dry air drilling attractive.

B.

NITROGEN DRILLING

In underbalanced drilling, nitrogen is sometimes substituted for air, or as a mixed component with air, as the drilling fluid. The advantage over air is that mixtures of nitrogen and hydrocarbon gases are not flammable, removing the hazard of downhole fires. The circulating gas does not have to be pure nitrogen to prevent downhole fires. Mixtures of air, nitrogen and hydrocarbon are not capable of combustion, provided that the oxygen concentration is kept below a critical level. Figure 3-4 shows a graphical representation of the minimum concentration of oxygen required for a mixture of oxygen, nitrogen, and methane to become flammable. For example, at a pressure of 3,000 psi, an O2, N2, and CH4 mixture would have to contain slightly more than 8% oxygen to be flammable. This

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Underbalanced Drilling Shortcourse

effectively eliminates the hazard of a downhole fire. Combustion tests must be performed at the conditions that will be encountered in each project. In some conditions, like the presence of H2S, combustion must be maintained at or below 6% O2, below the normally accepted limits of combustion.

Oxygen Required for a Flammable Mixture (%)

12.0 11.5 11.0 10.5 10.0 9.5 9.0 8.5 8.0 0

500

1000

1500

2000

2500

3000

Pressure (psia)

Figure 3-4. The influence of pressure on the minimum concentration of oxygen required, % by volume, for a flammable mixture of oxygen, nitrogen and methane (after Allan, 1994, and Zebetakis, 1964).

1.

Equipment Selection

a)

Differences From Dry Air Drilling

The major difference between nitrogen and air drilling equipment is due to the substitution of nitrogen for air as the circulating fluid. There are currently two main methods of supplying nitrogen for drilling operations, cryogenic and membrane filter. Cryogenic operations necessitate delivery of nitrogen to the location as a liquid and stored cryogenically. A membrane filter operation, on the other hand, is capable of producing nitrogen on site, by separating nitrogen from ambient air through the membrane. b)

Cryogenic Nitrogen Supply

Nitrogen is used in field applications throughout the world, in well completions, stimulations, production operations and drilling operations. For most of these practices the nitrogen is transported to the wellsite as a liquid. Cryogenic tanks are necessary for transporting the liquid nitrogen to location, because the boiling point of nitrogen (at atmospheric conditions) is -321°F. The pumping unit consists of a diesel driven, positive displacement pump and a heat exchanger. The liquid nitrogen is pumped from the cryogenic tank through a heat exchanger that evaporates the liquid, and discharged as an 80°F to 120°F Gas. There are a number of service companies that provide nitrogen units, in various sizes and capacities, to most parts of the United States. These units have maximum delivery rate and pressure specifications, but usually power restrictions will prevent them from reaching both limits concurrently. Small units typically are able to deliver 1,100 scfm at pressures up to 3,000 psi, but as the delivery pressure increases towards the unit’s pressure rating of 4,500 psi, the delivery rate will fall. Larger units are capable of delivery rates to 6,000 scfm at pressures up to 8,000 psi.

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For drilling applications utilizing a cryogenic nitrogen supply, the bank of compressors/boosters are replaced with a nitrogen pump unit. The nitrogen is pumped as a liquid and converted to a gas. Since this conversion is well characterized at standard conditions, the measurement of the gaseous nitrogen delivery rate is easily and accurately accomplished. Each gallon of liquid nitrogen generates approximately 100 scf of nitrogen gas. For a typical drilling operation with a volumetric flow rate of up to 2,000 scfm, this means that up to 30 bbls, or roughly 5 tons, per hour of liquid nitrogen will be required. c)

Membrane Filters

The generation of nitrogen on-site can be a viable alternative to the use of cryogenic storage systems. The surface system used to perform nitrogen drilling is based on the same equipment, compressors, boosters, and mist pumps, as dry air drilling with the incorporation of an air cooler and oxygen filter membrane, shown in Figure 3-5. Conventional air compressors deliver the air, at a pressure of 150 psi. The compressed air is cooled to approximately 80°F and passed through a series of primary filters. These remove contaminants, such as dust, compressor lubricant oil, and atmospheric water. The air flow then passes through the membrane filter which consists of an array of many very fine, hollow polymeric fibers. The lighter nitrogen molecules pass down the fibers, while heavier oxygen molecules penetrate the fiber walls. The two gases are separated. Nitrogen is delivered to the booster unit and then to the standpipe. Oxygen is vented to the atmosphere. Nitrogen concentration in the gas flow delivered by these membrane filters can be readily controlled, and can range from 92 to 99.5 percent. Nitrogen purity is controlled by varying the air input rate and the back pressure on the filter unit. One disadvantage of using onsite produced nitrogen is corrosion. The oxygen contained in the membrane produced nitrogen causes corrosion and must be addressed as in air or mist drilling. Some expense for corrosion control will offset the nitrogen savings to some degree. Onsite produced nitrogen is usually cheaper overall Ambient Air In

Compressor(s)

Water Filter

Hydrocarbon Filter

Air Cooler

Oxygen Filter Membrane

Particulate Filter

Membrane Skid

Booster(s) Mist Pump

Nitrogen Into Standpipe

Figure 3-5. Schematic of a nitrogen drilling system using membrane filter generation (after Allan, 1994).

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Other Equipment

Firestops or firefloats in the drillstring are not needed when drilling with nitrogen. Otherwise, the equipment used is essentially the same as that used for dry air drilling described earlier.

2.

Operational Procedures

Operating procedures for nitrogen drilling are no different from those described for dry air drilling. Although the risk of downhole fires is removed, the possibility of stuck pipe occurring from the formation of a mud ring is still a very real concern. Timely detection of the symptoms of mud ring formation is still essential to a successful drilling operation. The release of an abundance of nitrogen and enriched oxygen into the atmosphere poses few risks although some attention is necessary. Dispersion of the discharged oxygen should not be obstructed so it does not accumulate in one area. A modest increase in oxygen concentration can result in dramatic changes in the combustibility of materials. 3.

Limitations

One of the major limitations of dry air drilling can be removed by using an appropriate concentration of nitrogen as the circulating medium. Nevertheless, the other limitations of dry air drilling still apply when nitrogen is used. The formation of mud rings, as discussed above, is still a hazard. It is acceptable to use nitrogen as the gaseous phase in mist or foam drilling to overcome excessive water production problems. The predominate limitation to using nitrogen for drilling is economics. The nitrogen supply is costly, regardless of how it is generated. The quantities of liquid nitrogen required can easily cost up to $35,000 per day of drilling. And a daily incremental cost of over $7,000 can be associated with the use of a membrane filter, which includes the cost for rental of the compressors, boosters, and mobilization. As a result of its high cost, nitrogen is normally only used when drilling through a long producing interval, as would be the case in a horizontal well. The use of nitrogen drilling in a long vertical well would be difficult to justify, unless encountering multiple zones of interest. Nitrogen could be recycled if a closed surface system is used. This would make the use of nitrogen more economical, although the savings in nitrogen cost would be partly offset by the additional cost of the surface equipment that might be involved. This will be discussed again in Section III.G “Gasified Liquids." 4.

Summary

a)

Advantages

The advantages of nitrogen are very similar to those seen in dry air drilling. The major advantage is the elimination of downhole fires. Due to the costs, nitrogen is generally not used in long vertical wells. More commonly, nitrogen is used in long horizontal sections where formation damage or lost circulation is a concern and downhole fires are a problem. b)

Disadvantages

The disadvantages of nitrogen drilling are cost, water inflows, wellbore instability, limitation of downhole measuring devices, encounters with sour gas, and corrosion from onsite generated N2. Cost is a significant consideration when considering N2. Water inflows can cause real problems in cuttings removal, stuck pipe, and hole stability. Wellbore stability can become a real problem if

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formations are encountered where the mechanical stresses are not strong enough to keep the borehole from collapsing. Also, wellbore stability is a problem where water inflow is sufficient to cause sensitive shales to slough. Typical downhole measuring equipment, like MWD, cannot be used. Instead, specialized equipment like EM MWD must be used when necessary. If onsite generated N2 is used, corrosion must be considered. c)

Design Criteria

Underbalanced drilling with nitrogen should be given consideration when any of the following criteria exists: Vertical wells with the following •

Multiple formations of interest that are considered to be damaged easily by drilling fluids.

Horizontal or highly deviated sections of wells with the following

C.

•

Areas with known loss circulation problems,

•

Formations that are considered to be damaged easily by drilling fluids,

•

Formations with adequate strength to withstand mechanical stresses without collapsing,

•

Areas with limited ground water flow,

•

Areas where downhole fires are a major concern.

NATURAL GAS DRILLING

In underbalanced drilling, natural gas can be substituted for air as the drilling fluid. The advantage of natural gas over air, like nitrogen, is that when encountering other hydrocarbon gases the result is not flammable, since there is no oxygen source. This removes the hazard of downhole fires, but does present the possibility of a surface fire. For this reason, it is recommended that the returns be flared. 1.

Equipment Selection

Due to economics, natural gas drilling is usually only considered when the gas can be obtained directly from a supply pipeline or nearby well. In most instances the pipeline operator will provide a drill gas unit. This unit consists of a scrubber and an orifice meter that connect to the pipeline. a)

Surface Layout

A typical surface layout is shown in Figure 3-6. The basic layout includes a drill gas unit, three-phase separator, booster unit, adjustable choke, blooey line jet, drillers manifold, emergency vent line, and standpipe relief line. Check valves and valves have been installed in appropriate locations.

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Underbalanced Drilling Shortcourse Drill Gas Unit with Meter Run

3 Phase Separator Booster

Water Oil Dump Dump

Drillers Manifold

Standpipe

Adjustable Choke

To Blooey Line Jet

Emergency Standpipe Vent Line Relief Line

Figure 3-6. Typical surface equipment required for drilling with natural gas b)

Supply Line

A supply line is commonly used to transport the natural gas from the pipeline to the rig. This line is customarily 3 inches in diameter and can be as long as one half mile. To ensure that adequate delivery is available at the rig, pressure drops along the supply line should be considered. Refer to Appendix C of the GRI Underbalanced Drilling Manual for more information on pressure drops. c)

Three-Phase Separator

The removal of water or any liquid from the supply gas is extremely important. If a compressor or booster is used, the supply gas needs to be as dry as possible to prevent internal damage. Also, liquids in the injection stream can cause the formation of mud rings or cause wellbore instability. Often a three-phase separator is installed upstream of any compressors/boosters and downstream of the drill gas unit. Careful planning should be given to the working pressure and temperature ratings of the vessel chosen for the separation process. The vessel should be able to handle flow in excess of the highest required gas injection rate. d)

Compressors/Boosters

These pieces of surface equipment may or may not be required. This can be determined by examining the pipeline pressure and the anticipated gas injection standpipe pressure. Even if pressures are considered to be adequate, it may still be advisable to have a booster available in case downhole problems require a higher standpipe pressure. Make sure that any compressors or boosters used in the process are rated for natural gas service. e)

Adjustable Choke or Pressure Regulating Valve

The supply gas should flow through an adjustable choke or pressure regulating valve so that the flow rate can be controlled during drilling and tripping. The choke or valve should be located downstream of the booster.

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Valve Manifold

Immediately downstream of the choke or regulating valve the gas flow is directed into a three inch valve manifold, similar to the air header discussed in Section III.A “Air Drilling." Ideally this manifold is located on the rig floor, next to the drillers console. This manifold should be set up to allow gas to be sent to the blooey line primary jet or to the standpipe. The manifold should also allow the ability to independently vent the gas delivery line and the standpipe. Both of these vent lines should be a minimum of 2 inches in diameter. If it is desirable to measure the gas production rate, additional lines from the choke manifold to the flare pit should be installed. These lines should pass through a flow tester and exit to the flare pit. They must be rated for the maximum anticipated well flow rate and wellhead pressure. g)

Gas Detectors

It is recommended that hydrocarbon gas and hydrogen sulfide detectors be located on the rig floor and well cellar. Another hydrogen sulfide detector should be located at the blooey line exit. Care should be taken when locating this hydrogen sulfide detector to place it so it will not be damaged by the flare! Since the drilling medium is natural gas, there is no point in locating a hydrocarbon detector at the blooey line exit. h)

Flaring Arrangements

The gas delivery vent lines and the standpipe vent lines should run to the flare pit. It is recommended that this flare pit be separate from the main flare pit into which the blooey line discharges as shown in Figure 37. The blooey line should have a cross-sectional area that is equal to or greater than that of the annulus. The minimum length of the blooey line should be 150 ft and should be run to the main flare pit. Main Flare Pit

’L 150 ine yL e o o l 7” B

ong

2”

ine yL looe oB t e Lin

Jet

Orifice Well Tester

Choke Manifold Flare Pit Rotary Table 3” Supply Gas Line

Dog House

Driller’s Manifold

Figure 3-7. Flaring arrangements for drilling with natural gas (after Cummings, 1987)

2.

Operating Procedures

The operating procedures for drilling with natural gas are similar to those used when drilling with dry air or nitrogen. The gas delivery rate can be controlled by adjusting the choke in the supply line or by adjusting the pressure regulating valve to achieve the rate which will yield the desired standpipe pressure.

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Hole Cleaning

At the same volumetric rate, natural gas is usually less efficient than air at transporting cuttings. The density of natural gas is usually different from the density of air, at the same temperature and pressure. In general, the specific gravity of natural gas is less than that of air (Sair = 1.0 @ STP); therefore, decreasing densities are naturally less proficient for cutting transport. Keep in mind that the specific gravity of natural gas varies from reservoir to reservoir, sometimes even from well to well. The minimum gas injection rate required for efficient cuttings transport varies with the specific gravity. The required gas rate increases in inverse proportion to the square root of the gas’s specific gravity. An estimate of the flow required can be calculated by dividing the calculated air flowrate by the square root of the gas specific gravity. For example: drilling with 0.7 SG gas, the rate would increase by a factor of 1/√0.7 = 1.2 . Refer to GRI Underbalanced Drilling Manual for a more in depth look at calculating terminal velocity. Remember that natural gas is not an ideal gas and behaves differently than an ideal gas. Natural gas is characterized by a phenomenon known as “super compressibility," meaning that it compresses more readily at some pressures than does an ideal gas. If control of the bottom hole pressure is critical, for example maintaining the underbalanced pressure within a specific range, then the real compressibility of natural gas should be considered. Natural gas is considerably more expensive than compressed air. The most cost effective injection rate is most likely the recommended minimum rate. The size of the hole to drill will have a substantial impact on the gas injection rates, and therefore the costs. Increasing the hole size from 6-1/4 inches to 6-3/4 inches would require about a 15-20 % increase in gas injection rate. Expanding to 7-7/8 inches would increase gas consumption by as much as 40%. b) Connections It may be necessary to unload the compressors during connections to reduce the amount of CH 4 being flared. c)

Tripping

The drillstring should be stripped through the rotating head when tripping out, as far as possible, before the rubber seal element is pulled from the rotating head. After pulling the seal, the gas flow should be directed to the primary jet to divert any gas away from the rig floor. Without fail, the cost of rotating head rubbers is predictably lower than the cost of the gas used to jet the blooey line. d)

Water Inflow

If the well starts to produce water, it is recommended that mist or foam drilling be adopted. The formation of a mud ring is still a major concern in natural gas drilling. With no air in the drilling medium, downhole fires are no longer a concern, but a mud ring can still cause a stuck pipe incident. Since the returns are flared at all times, the presence of water in the returns cannot be easily seen at the blooey line exit. There should be a change in the character of the flame at the flare pit with a significant water influx.

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Low cuttings return at the blooey line will also be difficult to determine; thus, the standpipe pressure is about the only option for detecting the formation of a mud ring or water influx during natural gas drilling operations. For this reason, it is recommended that the pressure gauge on the standpipe have a resolution of 5 psi and be monitored at all times.

3.

Limitations

The greatest limitation to natural gas drilling is the necessity to have a supply of gas within a one-half mile range of the rig site. Comparisons have shown that the cost of using natural gas, instead of air, as the drilling fluid is approximately double. The cost of on-site generated nitrogen is generally more, but not by much, than the use of natural gas. There may be an environmental concern, due to the flaring of the gas, if the well is to be drilled close to habitation. These same concerns would exist in drilling with dry air, if natural gas is encountered. Water inflows are still a limitation when drilling with natural gas. The formation of mud rings, wellbore instability, and the costs associated with disposal of the produced water are definitely concerns.

4.

Summary

Natural gas should be considered as an option for underbalance drilling a well when downhole fires are a concern and when a natural gas supply is located close enough to the well site to make it economically viable. Natural Gas can be as low as 10% to 20% of the cost of cryogenic N2. a)

Advantages

The advantages of natural gas are the same as those of air or nitrogen. The main advantage over air, like nitrogen drilling, is the elimination of downhole fires and corrosion. If the supply of natural gas is close enough to the rig-site, the incremental cost is comparable to that of on-site generated nitrogen and less than that of cryogenic nitrogen. Natural gas costs about $0.30 per 100 SCF, membrane N2 is $0.50 to $0.75 per 100 SCF, and cryogenic N2 is $1.50 to $3.00 per 100 SCF. b)

Disadvantages

A disadvantage of using natural gas is that there is not always a supply source close enough to the rig site to make it a viable option. Also, in inhabited areas, there may be an environmental concern with flaring. The other disadvantages are similar to those of air drilling, with the exception of the elimination of downhole fires. Like nitrogen, the cost of natural gas prohibits drilling long vertical sections in most cases. c)

Design Criteria •

Underbalanced drilling with natural gas should be given consideration when any of the following criteria exist:

Vertical wells with the following •

Multiple formations of interest that are considered to be damaged easily by drilling fluids.

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Horizontal or highly deviated sections of wells with the following •

Areas with known loss circulation problems,

•

Formations that are considered to be damaged easily by drilling fluids,

•

Formations with adequate strength to withstand mechanical stresses without collapsing,

•

Areas with limited ground water flow,

•

Areas where downhole fires are a major concern.

In both vertical & horizontal •

A close enough supply of natural gas as to be economical.

Economics should be the deciding factor in most cases. Compare the cost savings realized from natural gas drilling to the additional equipment and materials that are required.

D.

MIST DRILLING

Mist drilling is principally used to avoid forming mud rings. Thus, mist drilling is commonly applied during dry air, nitrogen, or natural gas drilling whenever a modest water influx is encountered. This is accomplished by injecting small amounts of water, along with a surfactant and frequently a corrosion inhibitor, into the compressed air flow just upstream of the drillstring. These liquids and any water produced from the influx are dispersed into a mist of independent droplets of liquid. The droplets move at approximately the same velocity as the air or gas medium.

1.

Mist Vs. Foam

Mist drilling is only one of several different drilling techniques in which the drilling fluid is a two phase mixture of gas and liquid. Other drilling fluids which contain gaseous and liquid phases include foams and aerated, or gasified, muds. These are sometimes collectively termed “lightened drilling fluids." a)

Differences

The droplets in a mist are not connected to one another; that is, the liquid phase is discontinuous. In a foam, the liquid is continuous and forms the walls of closed cellular structures that entrap the discontinuous gaseous phase. A mist is formed when the liquid volume fraction is below one to two percent, at the prevailing pressure and temperature. When mist drilling is the desired technique, the volume of liquid and gas injected into the well are controlled to insure that the drilling fluid is a mist as it flows down the drillstring. However, if there is a substantial water inflow, the liquid volume can increase to a point where a foam is created. As the fluid proceeds up the annulus, the pressure will decrease and the foam may or may not revert to a mist prior to returning to the surface. b)

When to Use Mist Drilling

If the drilling fluid is a gas (either air, nitrogen, or natural gas) and a modest water inflow is encountered, mist drilling should be considered. The mist flow will chemically assist in unloading the liquids from the wellbore. This will prevent the formation of a mud ring, increase hole stability, and allow movement of the string preventing stuck pipe. If circulation rates are a concern, foam drilling should be considered. The foam has a dramatically higher viscosity than either dry air or mist. This will allow effective hole cleaning at much lower circulation rates than necessary for mist drilling.

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2.

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Equipment Selection

As previously mentioned, typically mist drilling is initiated during a dry air drilling operation that has encountered a moderate water inflow. Most of the equipment for mist drilling is similar to that discussed in the dry air drilling section. If mist drilling is the primary method used on a well, small differences in equipment are desired. The water tank supplying the liquid to the mist pump usually has a storage capacity of 10 bbls. In an operation where mist drilling is the preferred method, a larger storage capacity would be desired. a)

Mist Pump

Skid mounted mist pump units are usually available in areas where air and mist drilling are common practice. A typical mist pump will come with two compartmentalized tanks on the same skid. The tanks usually have a volume of 10-20 barrels and are generally equipped with a simple gauge, consisting of a steel rod in the tank with marks for each barrel of tank volume. Mist injection rates, reported in barrels per hour (BPH), can be sufficiently measured utilizing these gauges. These pumps are not necessary for dry air drilling; however, it is recommended that they be a standard part of the surface equipment. During the drilling operations it is possible that water influx can occur. If this happens, these pumps make it possible to switch to mist or foam drilling to control the water influx. These pumps usually have high pressure ratings and small displacements, and are generally not more than 10 hp. b)

Water Supply

An adequate water supply should be available to allow the water reservoir of the mist pump unit to be refilled without interference to drilling operations. It is conceivable to recycle water from the reserve pit, reducing water storage requirements. However, this option does require careful consideration of the following factors. •

Injection water would have to be essentially solids-free. If water with a high solids content is used, serious damage to the injection pump could occur. The return water would have to remain in the pits long enough for all cuttings to settle out. The depth of water above the pit bottom (and cuttings) would need to be such that water can be drawn off without including the solids.

•

Formation water lifted from the well must be compatible with any additives (i.e. surfactants, corrosion inhibitors, etc.).

•

It can be difficult to assess the concentration of the various additives present in the recycled water. In a closed system, total liquid returns can be used to calculate dilution. In a pit, Cl- can be used if influx water Cl- is known.

•

A suitable air-driven or centrifugal pump should be rigged up to transfer water from the pit to the injection pump reservoir. The suction hose should be fitted with a good strainer and it should be supported to prevent the suction end from sucking any solids that are in the pit. For this, a floating suction is normally used.

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Surfactant Pump

When a separate surfactant injection pump is used, assure that it has the capacity to deliver from 0.25 to 5 gallons per hour. The pump should have a delivery pressure that meets or exceeds the highest expected gas delivery pressure. The surfactant unit requires a much smaller reservoir than is necessary for the water injection system. Note that the surfactant can be pumped directly from the drums. d)

Compressors

Due to higher flowing densities, the air injection rates for mist drilling are typically 30-40% higher than those for dry air drilling. For this reason it may be necessary to plan for an additional compressor(s). Also, note that the standpipe pressures can be as much as 100 psi higher than those observed during dry air drilling. e)

Waste Water Storage

All the logistics for liquid collection and storage should be confirmed prior to commencing drilling operations. Standard practice is to direct the return flow of mist and cuttings into a system of flare and reserve pits. Large volumes of liquid will have to be contained at the surface during mist drilling. These volumes could be greater than 2000 BWPD. Surface equipment should be capable of containing this liquid until it can be disposed. Some disposal options are as follows:

f)

•

Recycling the water as previously discussed. If there is a considerable water inflow, some of these other options will need exploring.

•

If the well is in close proximity to others, it may be possible to inject the water in an injection well.

•

Re-inject the water into a permeable zone, cased-off above the interval being drilled.

•

Haul the water off-site by tankers to a designated disposal site.

Defoaming

During normal mist drilling activities, the volumetric fraction of liquid in the returns are too low to exit the blooey line as foam. However, when an adequate water inflow is encountered, the returns in the blooey line could exit as foam or foam could be produced in the reserve pit with any kind of agitation. It is recommended to make provision for defoaming, especially if water inflow is expected. One way to counter foam returns is to install a defoamer unit 3 to 6 feet upstream of the blooey line exit. One type of defoamer is a ring of small nozzles, equally spaced around the diameter of the blooey line, that would spray a defoamer uniformly into the return stream. If the formation of foam occurs in the reserve pit, a defoamer can be sprayed manually onto the pit.

3.

Operating Procedures

Most of the operating procedures are like those used during dry air drilling operations. The procedures that are unique to mist drilling are described below.

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Hole Cleaning

The liquid droplets in mist can be regarded the same as cuttings. They have a density about one-half that of typical cuttings and tend to be smaller than most cuttings. Consequently the droplets generally move with the same velocity as the gas (i.e. slip velocity = 0). Thus, the flow properties of the gas, in which the droplets are dispersed, tend to remain unchanged. This means that mist is no more efficient than dry air for transporting cutting from the wellbore. The drilling fluid density is increased by the addition of the liquid droplets. They can also add to the frictional pressure losses around the well. The bottom hole pressure is increased, compared to dry air circulation at the same volumetric rate, by both of these factors. The terminal velocity is reduced by this higher fluid density. The annular velocity is also reduced due to the increased bottomhole pressure. The overall result is that higher injection rates are required when mist drilling to obtain the same annular velocity as with dry air. Refer to the GRI Underbalanced Drilling Manual for a more in depth look at Hole Cleaning during Mist Drilling. Hole drag and an increase in standpipe pressure indicate the beginning of a packed-off annulus. When this occurs, pull off bottom to stop producing cuttings. Continue circulating and reciprocate the pipe to attempt to break up the obstruction. Do not attempt to pull the string without air circulation. The standpipe pressure will continue to rise until the obstruction is cleared or circulation is shut off. Both stuck pipe and a downhole fire require fishing and/or sidetracking. How high the standpipe pressure should be allowed to rise before shutting off circulation is determined by hole conditions and the bottomhole assembly. If the well is producing wet gas and the bottomhole assembly includes expensive components, like MWD or downhole motor, circulation should be shut down earlier than when the BHA consists of a bit and a drill collars due to potential loss from a downhole fire. b)

Corrosion Inhibitors

A corrosion inhibitor is used to protect the drillstring, and any exposed casing strings, whenever air is used as the gaseous phase in mist drilling. Be careful to select a corrosion inhibitor that is compatible with the surfactant. This will prevent the creation of unwanted emulsions in the returns. Also, if it is known that water inflow will occur and what the composition of that water is, compatibility with the corrosion inhibitor should be reviewed. Temperatures are higher than static bottom hole during mist drilling. Allowance should be made for these higher temperatures when specifying the temperature range for the corrosion inhibitor. c)

Liquid and Solid Additives

Any additives to be used in the drilling fluid are usually added to the mist unit tank. Once the tank is full, add additives such as corrosion inhibitors, potassium chloride, and polymers. The tank can be physically stirred, or rolled by using a small amount of air from the compressors. Adding the surfactant last will prevent excess foaming. When using powdered additives, it is better if they are mixed with water in the mud hopper and then transferred to the foam unit tank. Since the hopper is capable of shearing action, a better mixing job will be achieved. The surfactant should only be added in the mist unit tank or an excessive amount of foam will be produced.

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Underbalanced Drilling Shortcourse

Monitoring Returns

The returns flowing through the blooey line should be monitored carefully when mist drilling. The type and volume of the returns are very significant to a successful operation. Continuous returns must be maintained throughout the entire drilling regime. When the water injection rate is too low, a mud ring could form and restrict circulation. This brings about the inherent danger of stuck pipe or a downhole fire. If returns stop, the water injection rate should be increased immediately. When the gas injection rate is too low or the concentration of surfactant is too low, slugging can occur. When slugging transpires, the standpipe pressure will fluctuate noticeably. Increasing air and liquid rates should stop the slugging. e)

Tripping

During mist drilling when the drillstring is tripped, water inflow is probably occurring downhole. If water is encountered while tripping back in the hole, the well will have to be unloaded before drilling can resume. Procedures for accomplishing this were discussed in the “Dry Air Drilling” operating procedures section. When the amount of water is significant, it is not advisable to trip to bottom and attempt to circulate the water out. Circulation may not be achievable and stuck pipe is a possibility. In this case the hole will have to be unloaded in stages. The length of each unloading stage needs to be shorter than when emptying casing, since formation water continues to enter the wellbore while tripping each stage. The hydrostatic wellbore pressure to overcome and break circulation equals the length of each stage plus the influx volume. After staging to bottom, do not resume drilling activities immediately. First circulate the well until the water in the annulus has been reduced.

4.

Limitations

The primary reason to perform mist drilling is to avoid the formation of mud rings when a water producing zone is encountered while dry air drilling. As previously discussed, a mud ring can often be a predecessor to stuck pipe or a downhole fire. The water in the circulating mist saturates the cuttings and the surfactant prevents the cuttings from adhering together downhole. The liquid in the drilling fluid significantly increases its thermal capacity. This diminishes any temperature increase that transpires when the circulating fluid is compressed by a flow obstruction, therefore further decreasing the chance of ignition. When the annular velocity is inadequate to clear the wellbore of cuttings, it is possible for the annulus to pack off, even without the formation of a mud ring. This is more likely in a highly deviated or horizontal hole. The required circulation rates in these instances are much higher than those for vertical or nearvertical wells. As discussed earlier, the annulus may also close if large fragments slough off from an unstable formation. Any time the annulus has packed off, the possibility of stuck pipe or downhole fires is extremely high. Other limitations to mist drilling include increased air compression, waste water disposal, increased wellbore instability and corrosion of downhole equipment. These are discussed below. a)

Air Compression

Mist drilling generally requires higher air injection rates, 30 to 40 percent higher, than required for dry air drilling, at the same depth and penetration rate. Standpipe pressure is also higher, about 100 psi, than for dry air drilling. This means that a higher compressor capacity is required and probably that a booster will be necessary. Increased equipment requirements increases daily fuel costs.

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Waste Water Disposal

Waste water disposal costs can be a very real economic limitation to mist drilling. Typical daily injection ranges from 1,000 to 2,000 barrels. Normally this water is not recirculated. The disposal costs are often $1/bbl to $10/bbl. The produced water can quickly exceed the surface storage capacity when encountering a large water inflow. Sometimes large reserve pits are built to manage the expected water production. If the reserve pits are filled, the options are to abandon mist drilling and mud up, reinject the water, or to haul away some of the produced water for off-site disposal. Materials injected into the well, like surfactants and corrosion inhibitors, add to the total program cost. And in remote locations, the water supply costs can be significant. These cost related factors limit the use of mist drilling. c)

Wellbore Instability

As discussed in dry air drilling, wellbore instability can result due to large variances between the effective stresses in the formation(s) adjacent to the wellbore and the pressure of the drilling fluid. The wellbore pressure is generally higher when drilling with mist, but the difference is small in comparison with the rock stresses. If mechanically induced instability is encountered when dry air drilling, there is little chance that mist drilling will improve wellbore stability. If weak or poorly consolidated formations are penetrated, mist drilling probably should not be considered as an option to increase wellbore stability. Since the volumetric gas flow rate is usually higher and the density of the circulating fluid is higher than it is for dry air drilling, wellbore erosion usually accelerates. If wellbore erosion is suspected, stable foam drilling would probably be a more appropriate option, due to much lower annular velocities. When water sensitive shales are encountered during dry air drilling, the shales normally dehydrate and slough into the wellbore. During mist drilling, the water in the drilling fluid can chemically hydrate the shales, causing them to swell and induce undergauged holes and wellbore instability. The addition of salts or polymers can inhibit shale hydration, but these additives can add considerable costs to the well. If shale hydration is causing a substantial amount of problems, it may become more cost effective to switch to a conventional mud system. In some areas operators have run an intermediate casing string to isolate water producing zones and then continue with dry air drilling. d)

Corrosion

When mist drilling, the potential for rapid corrosion of downhole equipment increases due to the high oxygen concentration in the aqueous phase, which encourages corrosion of exposed steel. Anodic regions, which are more prone to corrosion, are created when the rotating drillstring impacts against the hole wall and the casing. Any oxide film that forms on exposed steel tends to be removed by impact and by the erosive action of the cuttings in the return flow, allowing corrosion to proceed without hindrance. Protection against downhole corrosion can be obtained with the addition of a corrosion inhibitor to the injected water or the foaming agent. The corrosion inhibitor must be compatible with the foamer and with any other chemicals added to the injected water. Many of the foaming agents used in mist drilling are anionic; therefore, anionic corrosion inhibitors are required. Of those readily available, complex organophosphate esters are the most widely used and successful in mist and foam drilling applications. Film forming inhibitors, the most commonly used in liquid systems, are not usually successful in mist or foam drilling. The temperature at TD while drilling with mist are higher than when drilling with mud and higher than the calculated geothermal temperature. This must be considered when specifying the temperature range

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for the corrosion inhibitor. If the static BHT is close to the upper limit of the corrosion inhibitor, it is likely that there will be corrosion while drilling. Ensure that the upper limit of the corrosion inhibitor is far enough above the calculated to stand the extra heat when drilling. e)

MWD

The same limitations utilizing conventional MWD tools experienced in air drilling are evident in mist drilling. If it is necessary to have real time downhole measurements while drilling, EM MWD tools or comparable will be required.

5.

Summary

Mist drilling is generally a technique used when, during dry air drilling, water inflow is encountered. The liquid injection allows for the introduction of surfactants and corrosion inhibitors. The surfactant in the mist helps to unload any liquids in the wellbore caused by a moderate inflow of water. This method inhibits the formation of mud rings and minimizes the danger of downhole fires, while also preventing stuck pipe incidents. a)

Advantages

The advantage of using mist drilling, instead of dry air drilling, is preventing mud ring formation. The aqueous phase in the circulating fluid saturates the cuttings, and the surfactant in the foaming agent prevents the cuttings from adhering together downhole. The thermal capacity is increased which decreases the chances of igniting any hydrocarbons present. The following advantages are in comparison to conventional mud systems. Some of the other underbalanced drilling techniques, like air and gas, may be more advantageous than mist drilling.

b)

•

High penetration rates and reduction in rig time,

•

Low bit cost,

•

Low water requirements,

•

No mud removal,

•

Modest additives cost.

Disadvantages

The disadvantages of mist drilling, in comparison with dry air or gas drilling, are as follows: •

Increased air compression required,

•

Waste water disposal problems and costs,

•

Wellbore instability, both mechanically and chemically induced,

•

Corrosion of downhole equipment,

•

Cost of extra additives to control some of the above disadvantages.

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All of these disadvantages add cost to the overall operations. These are some of the reasons why mist drilling is usually not planned from the start, but instead used only when necessary. c)

Design Criteria

Underbalanced drilling with mist, a two phase flow consisting of a discontinuous liquid in the gas, should be considered only when water influx becomes a problem. Mist drilling should only be used in slight to moderate water inflows If there is a heavy water inflow, foam drilling should be implemented instead.

E.

STABLE FOAM DRILLING

Stable foam was first developed in the late 1960’s. It was originally used as a circulation medium to clean out production sand in depleted wells. It was discovered that stable foam has a carrying capacity up to ten times greater than common drilling muds. Eventually the industry began to utilize foam as a drilling medium. This includes drill-ins, drilling in lost circulation zones, coil tubing drilling, and underbalanced drilling in depleted zones. The principle reason for stable foam drilling is the ability to lift large amounts of water from the well without requiring excessive air rates and pressures. Foam allows underbalanced drilling without the high erosional velocities of air drilling while providing similar ecological advantages. It improves borehole stability with some hydrostatic support for the formation without creating a balanced or overbalanced situation.

1.

Discussion Of Foams

Foams incorporate a continuous liquid phase which forms a cellular structure that entraps a discontinuous gas. Foams normally have a remarkably high viscosity. The viscosity of foams are greater than either the liquid or the gas they contain. At the same time, their effective density range is from 0.2 sg to 0.78 sg, or 1.7 to 6.5 ppg. This combination of high viscosity and low density can provide several benefits to drilling operations. The following benefits are made in comparison to dry gas or mist drilling. •

The high viscosity yields efficient cuttings transporting. Annular velocities and required gas injection rates are much lower than in air drilling.

•

The low density of foam allows underbalanced conditions in nearly all circumstances. Bottom hole pressure with foam tends to be higher than air drilling. This may reduce penetration rates; however, penetration rates are still considerably greater than those attained with mud drilling.

•

Higher annular pressures can essentially reduce mechanical instability of the wellbore. The low annular velocities greatly reduces the possibility of erosion of the wellbore or the drillstring.

While it is possible to make foam with a number of gases, air is the most commonly used. The liquid phase is invariably aqueous. Because this liquid phase is continuous, a foam formed with air will not normally permit combustion of produced hydrocarbons. In many instances air foams are used to put out hydrocarbon fires.

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One of the greatest benefits of foam as an underbalanced drilling fluid is its capability to lift abundant amounts of produced liquids. When water inflows are in excess of the capacity of mist drilling to efficiently remove the liquids, foam allows the ability to continue drilling underbalanced. a)

Foams

A foam is made up of an assemblage of gas bubbles in a continuous liquid matrix. Pure water cannot form a foam, since any bubbles blend as soon as they contact one another. A surfactant, the foaming agent, in the liquid phase stabilizes the films that form the bubble walls and allows the foam structure to persist. There are several terms utilized to describe foams. These terms are bubble shape, quality and texture. Foams are classified according to the shape of the bubbles contained in the foam. Sphere foams are ones which contain very small bubbles that are spherical in shape and are usually freshly generated. This type of foam generally has the highest liquid volume fraction. Polyhedron foams consist of bubbles in the shape of polyhedras. Polyhedron foams contain a lower liquid fraction than sphere foams due to packing geometry. The quality of a foam is its gas volume fraction expressed in percent. A low quality foam or wet foam contains more liquid than does a high quality foam, called a dry foam. If foam quality exceeds an upper threshold level, the liquid phase becomes discontinuous and breaks down into a mist of dispersed droplets. A stable foam’s upper limit is not clearly defined, and depends on shear rate. The upper limit is also dependent upon the composition of the liquid phase, such as surfactants, viscosifiers, and liquid. The lower limit of stability is simply a question of definition based on the designation of a “lightened fluid” or a “stable foam." It has been defined between 55-75%. The range used in drilling is 60% to 99% depending on the characteristics of the foam and the location, whether at surface or downhole. The texture of a foam is described by the size and distribution of its bubbles. A fine foam has small bubbles and a coarse foam has large bubbles. A sphere foam is generally a low quality, fine foam. A polyhedron foam is usually a high quality, coarse foam. All foams are categorically unstable, yet low quality sphere foams tend to decay slower than do coarse polyhedron foams. There are two processes that cause the foams to decay. These are thinning of the bubble walls and growth of large bubbles at the expense of smaller ones. The thinning of the bubble walls is due to gravity. Bubbles tend to rise to the top of the foam and the liquid drains through the bubble walls to the base of the foam. Eventually the walls will become so thin that they rupture. Stirring a low quality sphere foam to re-distribute the bubbles can prevent thinning. However, agitation of a high quality polyhedron foam will accelerate rupture of the thinned bubble walls. The liquid’s surface tension inside a bubble tends to cause the wall to collapse. This effect has a tendency to be balanced by the gas pressure inside the bubble. This pressure is inversely proportional to the bubble size. When a large bubble contacts a smaller bubble, the higher gas pressure inside the smaller cell causes the gas inside it to diffuse through the liquid separating the two bubbles, until the smaller bubble is fully absorbed by the larger. The stabilization of foams can be accomplished by augmenting the strength of the bubble walls and by retarding the drainage of liquid via the walls. Surfactants are not only used to create the bubbles, but also to strengthen the bubble walls against disproportionate thinning. Proteins used in the liquid phase of an air foam will react with oxygen at the air-liquid interface to form a skin. Drainage can be diminished by increasing the bulk viscosity of the liquid phase. Additionally, drainage is reduced using surfactant mixtures to increase the surface viscosity of the base fluid.

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Foaming Agents

Surfactants are the principal agents used to generate foams. Not all surfactants will perform as foaming agents. Some tend to destabilize the foam structure and are therefore used as defoamers. Currently the most widely used foaming agents are ammonium salts of alcohol ether sulfates. These are anionic surfactants that are highly soluble in most liquids. They create a foam that has a very good thermal stability and is extremely well adapted to low surface temperatures; however, they tend to be costly. Other and less expensive anionic foaming agents operate well in fresh water and are resistant to hydrocarbon contamination. On the other hand, they lose their foaming capabilities in brine and cannot endure low surface temperatures. Cationic surfactants are not common foaming agents used in drilling operations due to poor stability and high required concentrations. Nevertheless, cationic surfactants may be worth considering to drill water sensitive shales because of their ability to stabilize clays. In general there are three main influences on a foam’s stability. The concentration of the foam, contamination, and temperature all effect the stability of the foam. Increasing the concentration of the foaming agent will ordinarily increase the stability of a foam. Measuring the half-life of the foam helps determine the foam's stability. The half-life of the foam will increase in direct proportion to the concentration of the foaming agent in normal drilling concentrations. If the foam is contaminated with brine or hydrocarbons, stability can be significantly reduced. The third important influence on stability is temperature. Typically as the temperature increases, the rate of foam decay increases. As the temperature downhole increases, it is necessary to increase the foaming agent concentration. c)

Defoaming

When a foam is correctly formulated, it can have a half-life of many minutes or even hours. As a result, large volumes of foam can quickly amass at the surface when circulated at typical rates. This can often necessitate the need to accelerate the decay of the foam once it has returned to the surface. The methods to break the foam at surface are chemical, mechanical, and combined chemical and mechanical. There are a variety of chemical defoamers available. Selection is based on the foaming agent used and lab testing to determine the best defoamer for a particular system and the necessary concentrations to break the foam. Defoaming is also possible by mechanical means. If a high quality foam is used, it is sometimes sufficient to agitate the foam, thereby rupturing the bubble walls. On the other hand, if a low quality sphere foam is used, any agitation can actually increase the half-life of the foam by reversing any gravity induced phase segregation. Centrifugal forces can accelerate the drainage of the liquid phase, destabilizing the foam. Today there are various mechanical defoaming systems available and shown in equipment selection below. d)

Hole Cleaning

Stable foams have been shown to be a very effective media for cuttings transport and fluid removal from the wellbore. The rheology and pressure calculations for stable foam systems are quite complicated and highly disputed in the industry. (Refer to the GRI Underbalanced Drilling Manual for an in depth treatment of foam rheology and pressure calculations.)

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Equipment Selection

In general, the equipment used to drill with pre-formed foam is the same as that utilized for dry air or mist drilling. The following summarizes the additional equipment essential for foam drilling. a)

Compressors

The gas phase of the foam is most often provided by air compressors. The air rates used in foam drilling are usually lower than those for dry air or mist drilling. In most cases, this allows the use of fewer or smaller compressors. Exceptions may occur if an annular back pressure is applied, if jets are run in the bit, which is not a normal practice, or if a downhole motor is used. If a large water inflow is encountered or if liquid has to be unloaded from the wellbore, higher surface pressures will be required. It is recommended that when using low delivery pressure compressors a booster be included in the system. b)

Gas

The most commonly used gas in foam drilling is air. Other gases could be used such as nitrogen, natural gas, carbon dioxide, or exhaust gas. Generally, compressed air is the least expensive. To be sure, the relatively low gas rates required for foam drilling can reduce the additional cost of these alternatives. Whichever gas is used, adequate volume and pressure is essential. Refer to the GRI Underbalanced Drilling Manual for more details on the circulating pressures required for Foam Drilling. c)

Base Fluid

The liquid mixing tanks and injection pumps are similar to those used in mist drilling. Normally two 10 bbl mixing tanks are required. The liquid injection pump is fed from one tank, while mixing fresh liquid in the other. A higher capacity pump than that used for mist drilling may be required for foam drilling. Typically the liquid rates for foam drilling are in the magnitude of 10 to 20 gpm, although rates of up to 100 gpm have been recommended for efficient hole cleaning in deep, large diameter wells. Due to the serious impact of foam quality on hole cleaning, it is essential that adequate metering of the gas and liquid be provided. A flow meter in the mist pump suction line is recommended. d)

Foam Generator

A foam generator is the one fundamental addition to a conventional air/mist drilling compressor system recommended for foam drilling. This generator ensures that the two phases are thoroughly mixed. The most common type is positioned where the gas and liquid flows meet. The liquid is introduced into the gas flow through a small bore tube midpoint in the flow path. The mixture is then directed through a venturi-type flow constriction. Another type of foam generator is located downstream from where the two phases meet. This promotes mixing through baffle plates or even sand beds. It is not unequivocally apparent that a foam generator is required. However, there is evidence that surface generated foam is more tolerant of contaminants, like formation water or hydrocarbons, than a foam formed in their presence. Thus, it is more advantageous to use a foam generator, unless there are specific reasons not to do so.

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Portable Units

An alternative to traditional air drilling equipment is portable air foam units. There are a number of custombuilt, portable units available in the continental US. These units are primarily designed for completion and workover operations, but some have adequate output for foam drilling operations. The units generally contain air compressors, a booster, a divided mixing tank, liquid pumps, foam generators and metering system. f)

Mud Pumps

It is recommended to have mud pumps hooked up to the system allowing liquids to be pumped into the well immediately if downhole conditions require it. An ample amount of kill weight mud should be on location, and in most cases is required by regulation. g)

Drill String

Float valves are required in the drillstring. One should be located just above the bit and one near the surface. When drilling long intervals, it may be necessary to reposition the upper string float, or install another, to minimize the bleed down time, prior to making each connection. Fire stops (discussed in Section III.A.2 “Air Drilling") may not be necessary. An exception might be when drilling wells with long horizontal sections with an air foam. h)

Return System

It may become necessary to pressurize the annulus to control foam quality. For this reason, a choke should be located in the blooey line in close proximity to the rotating control head (RCH) or rotating blow out preventor (RBOP). If the program indicates that annular back-pressure may be required, then the additional pressure should be included when specifying the pressure capacity of the RCH or RBOP. The section of blooey line between the choke and the RCH or RBOP should also be rated to handle this additional pressure. In cold regions it is possible for the foam returns to freeze and plug the blooey line. If possible, an additional foam discharge line should be added. Both the blooey line and the foam discharge line should lead to the flare pit. The blooey line diameter should be equal to or greater than the cross-sectional area of the annulus and a minimum of 150 ft in length. The flare pit should be located far enough from the rig that the flare cannot ignite any gas incidentally released onto the rig floor. It is normal to discharge the returns into a combined flare and reserve pit. Since the discharge volumes are likely to be larger than those during air or mist drilling, the pit must be of adequate size, and arrangements made to handle excess amounts of return waters. It is possible to utilize a closed surface system during stable foam drilling, discussed later in Section III.K “Closed Systems”. I)

Air Separator

When fluid recycling is desired, a bowl shaped vessel with a stack, referred to as the air separator, is placed at the end of the blooey line above the shakers. The separator permits the majority of the air to escape and preserves water. Care should be taken that the air separator does not overflow. A fully opening valve placed in the blooey line can be partially closed to limit fluid surges. See Section III.K “Closed Systems” for more information on recycling.

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Defoaming Equipment

There are several available defoamer systems, all of which work by some form of accelerated centrifugal motion to assist in gravity induced separation. A hydrocyclone works well and there are two specially designed types of defoamers. The first is a corkscrew shaped flowpath that causes centrifugal acceleration. The second is a spinning perforated chamber that dumps air from the top and fluid from the bottom.

3.

Injected Fluid

a)

Foaming Agents & Chemical Additives

At a minimum, the injected fluid should include water, a foaming agent, and a corrosion inhibitor. The foaming agent should be chosen to accommodate the predicted downhole conditions. A method for evaluating foaming agents to be used in foam drilling is provided in API RP46. This method should be equally pertinent to foam drilling applications. •

The standard test liquids are fresh water, fresh water with 15 percent kerosene, 10 percent brine, and 10 percent brine with 15 percent kerosene.

•

Ten grams of silica flour are added to one liter of test liquid to simulate the presence of cuttings.

•

Foam, generated with the specific agent, is used to lift each of the four test liquids up a 10 foot long, 2.5 inch diameter model wellbore.

•

The quantity of test liquid collected in 10 minutes, taken at the top of the wellbore, indicates the foaming agent’s suitability for use in saline or hydrocarbon environments.

•

If possible, samples of actual formation fluids and cuttings should be substituted for the regular test liquids and solids.

The foaming agent concentration used in the injected fluid should be formulated by downhole conditions and the interaction between the foaming agent and any formation fluids that are expected to be encountered. Generally, the concentration of most commercial foaming agents used are in the range of 0.5 to 2 percent. An initial concentration of about 1 percent is often a good starting point. It is important that the concentration be modified to attain a level of foam stability that balances good hole cleaning with easy defoaming. Careful evaluation and selection of the corrosion inhibitor is vital to prevent severe corrosion of downhole equipment as depth and temperature increase. All corrosion inhibitors should be tested in the worst projected conditions to ensure that their effective limit is not exceeded. KCL or other shale hydration inhibitors may also be added. To create a “stiff foam,” viscosifiers may be added to the liquid phase. This is discussed in detail in the next section “Stiff Foam Drilling."

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Disposal Concerns

Almost all surfactants in foaming agents are biodegradable. Some of the components, however, may pose minor health or environmental risks. The hazard of these components should be described on their respective Material Safety Data Sheets (MSDS). In foaming agent selection, these hazards should be considered, especially if there are restraints on the disposal of waste liquids for the well in question. If the waste liquids are contaminated by formation fluids or other chemicals, the disposal of the fluids may be more difficult, even if the foaming agent itself is benign. Normally the injected fluids are not recycled. However, if the foam can be successfully collapsed and the fluid re-conditioned to the original specifications, recycling is an option. If this is possible, the consumable costs can be reduced by as much as 50 percent. Refer to the GRI Underbalanced Drilling Manual for methods to accomplish the recycling. Insure that an adequate water supply is available at the rig site in order to maintain the projected injection rate. c)

Chemical and Mechanical Defoamers

During foam drilling operations, a very large volume of foam can rapidly accumulate at the surface. It is standard practice to take measures to destabilize the foam. This process can be done by chemical or mechanical means, or a combination of both, as discussed earlier in the defoamer equipment.

4.

Operating Procedures

Stable foam drilling is similar to dry air drilling in many cases. Closely monitor standpipe pressure and foam quality at the pit. Mud rings seldom form during foam drilling so the changes in standpipe pressure and foam quality usually indicate influx. a)

Hole Cleaning

As in any drilling operation, the hole must be monitored for signs of poor hole cleaning. Excessive drag or fill may indicate a problem with foam quality or annular velocities and must be corrected. b)

Surface Indicators

If the foam is wet at the pit and the standpipe pressure is up, which indicates water influx, the downhole quality may be too low to lift cuttings. Additional concentration of foaming agent is required. With high water influx, additional air may also be required to lift the water. If the surface foam quality is too high, the foam may slug or revert to mist, indicative of gas influx. In this case the foamer rate (not concentration) must be increased. Either influx drives the foam out of its effective quality range and reduces the foam's ability to lift cuttings. Any influx will normally associate both a standpipe pressure increase and a change in surface foam quality. A change in surface foam quality without any pressure change may be a function of temperature or contamination and may require an adjustment in foamer concentration or rate.

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Making Connections

Connections while foam drilling are handled similarly to connections while air drilling. Depending on foam quality and half life, it may or may not be necessary to circulate bottoms up before making a connection. Stop liquid injection, divert the air flow to the primary jet, and jet the blooey line while making the connection. A portion of the foam in the well will collapse while making the connection. As in air drilling, circulation should be reestablished before picking up out of the slips. Drilling can continue when standpipe pressure starts to fall or when stable foam returns are resumed. d)

Tripping

Before tripping, it is important to circulate the well clean. During the trip, the foam will collapse and leave all cuttings and liquids on bottom. The requirements before making a trip are dependent on several factors. The amount and type of influx, and the quality and efficiency of the foam should be established to decide what to do before, during, and after a trip.

e)

•

Poor foam will leave cuttings in the well. Try to understand the cleaning efficiency of the system to predict fill, and use fill to understand how the foam system is working. Correct the system to clean the well before a trip.

•

Very little influx may make it desirable to blow the well dry with air before tripping. Shut down liquid injection and circulate out the foam with air. This will reduce the amount of water that must be dealt with when tripping in.

•

Water influx can fill a substantial portion of the wellbore and will require staging back into the hole. With high water influx, do not blow the well dry. Plan a staged reentry.

•

Gas influx can present a danger to the rig. If there is any chance that the well is producing gas, utilize the rotating head and annular to isolate the well from the rig floor and flare the gas. When the well is open, jet the blooey line. Close the blinds when possible and continue to flare the well.

Staging in the Hole vs. Unloading in one Stage

As in air drilling, it may be necessary to stage back into the hole. In contrast to air drilling, the option exists to use a low quality foam to clear the wellbore in one stage. A gradual increase in foam quality as the well unloads allows for the well to be unloaded in a single stage and converted back to high quality foam without excessive standpipe pressures. Be careful not to overbalance the well if this method is used. A rule of thumb in air drilling for staging into the hole is to take the available surface pressure and double it to have a stage length in feet. This provides 0.5 psi/ft to lift the water which is a fairly good number for unloading the well. With foam there is a variable amount of hydrostatic in addition to the surface pressure, so the stage can be as long as the formation pressure will support. Stages can be calculated based on a safe BHP and the quality of foam required to unload that column of water. If the formation will handle the pressure, unloading in a single stage with foam quality increasing as standpipe pressure decreases is the most efficient from an operational standpoint. f)

Mudding Up

If mudding up with significant gas flow is unavoidable, it may be necessary to divert the well through a choke to restrict the gas flowrate enough to kill the well. Precautions need to be taken to avoid over pressuring the shoe or open-hole section of the well. A dynamic kill program will help in calculating pressures and constructing a kill sheet to mud up without damaging the well.

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Limitations

There are a number of factors that limit the applicability of stable foam drilling. These include corrosion of downhole equipment, wellbore instability, downhole fires, waste water disposal, and consumable costs. Most of these limitations are common to air drilling and to mist drilling. a)

Corrosion

Factors that affect the corrosion caused by foam drilling are the same as mist drilling. The combination of oxygen and water at elevated temperature and the removal of corrosion products create a situation that is ideal for rapid corrosion. The addition of salts from the formation water or added as shale inhibitors accelerate the corrosion. In the presence of H2S the reduced thickness of the corroded steel is more susceptible to stress cracking than undamaged steel. These problems can be handled by the use of carefully chosen corrosion inhibitors, and sulfide scavengers or sour service materials. b)

Wellbore Instability

Stable foam drilling improves wellbore stability by removing cuttings at a much lower shear rate than air or mist drilling. The high viscosities and low velocities create little erosion in the wellbore. c)

Mechanical Instability

Mechanically induced wellbore instability, such as hole collapse or sloughing, is reduced by foam over air by reducing the pressure differential between the rock and the wellbore. The magnitude of the decrease in differential would be approximately 30% at 5,000’ due to hydrostatics. In some cases this may be enough to reduce or eliminate the sloughing. d)

Chemical Instability

Chemical instabilities, like shale swelling, caused by any water bearing fluid can usually be controlled by the addition of inhibiting salts. Stable foam carries a proportionally higher cost for the salts than mist drilling due to its higher water content. Water influx can make the cost prohibitive due to treatment of large amounts of water that must be disposed of once it reaches surface. e)

Workovers

Many shallow wells have been worked over by drilling a liner into place in an underpressured unconsolidated formation using stable foam. Attempts to conventionally drill these formations with stable foam were difficult because when circulation was stopped, the formation would slough into the wellbore. The circulating pressure of the foam was sufficient to support the wellbore while drilling but the hydrostatic pressure was insufficient. f)

Downhole Fires

The air in a stable foam is isolated and unavailable for combustion. In fact, air based foams are used in firefighting. The only reported cases of downhole fires with a stable foam system have been reported in horizontal wells. It is suspected that the foam in the horizontal section separated and created a continuous air phase that could support combustion.

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Waste Water Disposal Concerns

The primary reason for using a stable foam system is to lift water from the well. Because of this, large quantities of water can be expected and will have to be disposed. Poor planning for disposal and anticipated water volumes can create a situation where it is necessary to mud up before the well is at TD. h)

Consumable Cost

The cost of foam drilling can vary due to influx of salt water or liquid hydrocarbons. Contaminates can increase the required chemicals substantially and water disposal can increase costs. Typically this is not the case and stable foam systems provide a viable economic option.

6.

Summary

Stable foam drilling is a viable option in several cases. When significant water influx is expected or when wellbore erosion or stability is a problem, stable foams should be investigated as a possible solution. As with all underbalanced drilling techniques, the basic criteria still apply to candidate selection but some problems that are difficult with other systems are workable with a foam system. a).

Advantages

The stable foam system can handle large influxes of water or gas with proper monitoring and treating. The system is much less erosional than air or mist systems and supports the wellbore better. b)

Disadvantages

The stable foam system can be a corrosion problem like the mist system. In addition it is more expensive to treat than the mist because of total water content. c)

Design Criteria

A well that generally fits the underbalanced drilling criteria and has either large anticipated water influx or critical hole stability problems may benefit from the stable foam system.

F.

STIFF FOAM DRILLING

1.

Discussion Of Stiff Foams Vs. Stable Foams

Stiff foams are an adaptation of stable foam. These were developed for drilling very large diameter (64”) holes underbalanced. A stiff foam is very similar to a stable foam with viscosifying agents added to the mix water. By adding bentonite, polymer, or both, a foam can be constructed that is stable at qualities above 99.5% with increased lifting capacity compared to stable foam systems. The stiff foam surfactants, corrosion inhibitors, and stabilizers can be used in the same concentrations as the stable foam. The higher viscosity and quality exhibited by stiff foams allow for reduced consumable requirements and reduced flow rates when compared to stable foams.

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Rheology

The rheological properties of stiff foams depend on both the composition of the liquid phase and the quality of the foam. No thorough studies have been found on predicting stiff foam rheology but two general effects appear in the literature. The stiff foam can be expected to exhibit 3 to 4 times the viscosity of a stable foam of the same composition, without the polymer, and is heavily influenced by polymer concentration. The second general effect is that the viscosity ratio is less at very high qualities. This means that as the quality of a stiff foam drops, the viscosity drops less than it would with an equivalent stable foam. This feature makes stiff foams more tolerant of water influx because the viscosity does not drop as much for the same reduction in quality, and the initial quality can be higher. There are no predictive models for calculating circulating pressures for stiff foam systems. However, the surface pressures experienced when using stiff foams appears to be very similar to stable foams. The pressure increase expected due to higher viscosity is offset by the reduced flow rates. Because of this it is reasonable to use the pressure profiles generated for stable foam systems.

3.

Equipment Selection

In general, the equipment used to drill with stiff foam is the same as that utilized for stable foam drilling. The following summarizes the additional equipment essential for stiff foam drilling. The air requirements for stiff foam drilling are very low and may actually require fewer compressors than stable foam drilling. As in all air based drilling, the compressor system must have the pressure capacity to unload water. The fluid injection rates for stiff foam drilling are lower than stable foam drilling. The requirements for fluid injection set out for stable foam drilling are more than adequate. One additional requirement for stiff foam drilling is the capacity to mix the viscosified fluid. The rig's mud system is set up to mix both the amounts and types of materials used in the fluid so, in most cases, this is not a problem. If a special air drilling rig is contracted, make sure it has the capacity to mix, store, and transfer a minimum of 60 Bbl/Hr of viscosified fluid.

4.

Chemical Requirements/Foam Control

The typical stiff foam system is comprised of a polymer mixed in the 50 - 80 sec marsh funnel viscosity range with the foamer, corrosion inhibitor, and shale inhibitor added. The system is mixed in bulk without the foamer, then transferred to injection tanks for the addition of foamer and injection into the gas phase stream. Chemical concentrations are the same as stable foam systems. Most viscosifying agents will form a stiff foam but the most common are the polymers HEC, PAC/Cypan, PAC/XC, and CMC. The CMC system shows good calcium and chlorides contamination resistance. Further discussion and polymer loading can be found in the GRI Underbalanced Drilling Manual. Stiff foams have a longer half life than stable foams and the half life increases with the viscosity of the liquid phase. This can create problems at surface and may require a better defoaming system and larger pits. If there is any chance that it will be necessary to switch to a stiff foam system during a well this should be investigated thoroughly to avoid having to mud up when the pit is full of foam.

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Operating Procedures

Stiff foam drilling is identical to stable foam drilling with the following differences. a)

Mixing Injected Liquid

The base fluid, minus the foamer, is much more difficult to mix than non-viscosified fluids. If bentonite is used, it should be prehydrated and polymers must be mixed slowly and sheared thoroughly. The rig mud system is designed fairly well for the use of bentonite or prehydrated polymers. A dry polymer may require the addition of a poly-shear unit to eliminate fisheyes and fully yield the polymer. The required quantity and storage of fluid each day may need planning. For example, a 25 GPM fluid, equivalent to 850 Bbl/day, must be slowly mixed and stored while the next batch is started may require additional storage or attentive arrangements. Plan mixing times and volumes carefully. b)

Recognition of Inflows

The signs and effects of inflows into a stiff foam are very similar to stable foam drilling. The primary differences to be aware of are as follows: Stiff foam is normally run at higher quality and lower rates than stable foams. Gas influx will have a greater effect on the stiff foam system because the gas affects a smaller amount of foam, and the foam has less margin for increased quality. If slugging starts, increase liquid injection to resume foam returns. The advantage of stiff foam is its lifting capacity at lower quality. When drilling below a gas influx, with additional liquid injected to maintain returns, the low quality foam from the bit to the influx has more lifting capacity than a stable foam would at the same quality. This may allow continued drilling below a gas influx where a stable foam would not carry cuttings between TD and the influx. To improve hole cleaning, you have the additional variable of fluid viscosity as a parameter that can be adjusted. It may be more economic to increase the viscosifier concentration rather than foam flow rate if hole cleaning problems are encountered. Water inflows, as discussed earlier, are more easily tolerated with a stiff foam system and the reaction to water influx is the same as a stable foam system.

6.

Limitations

a)

Wellbore Instability

Stiff foam drilling improves wellbore stability by removing cuttings at a lower shear rate than stable foam drilling. The high viscosities and low velocities create little erosion in the wellbore. b)

Gas Flows

Gas influx, as noted earlier, is not tolerated well by stiff foams. An aggressive response to gas flows is necessary to avoid having the foam collapse in the borehole while closely following the foam quality between TD and the gas entry point. c)

Downhole Fires

The air in a stiff foam is isolated and unavailable for combustion. The additional stability of a stiff foam makes it less likely to separate in a horizontal well, and the lower gas rates make it more feasible to switch to an inert gas if necessary.

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Corrosion

Factors that affect the corrosion caused by foam drilling are the same for stable foam and stiff foam. The same solutions exist but cost must be considered in the overall plan. e)

Consumable Cost

The polymers necessary for a stiff foam increase the cost of drilling substantially. However, this cost can be partially or fully offset by reduced requirements for water, compressors, and chemicals. As in any underbalanced drilling operation, the cost may be justified by production, reservoir, mechanical, or operational considerations. If it is the only way to reach TD, and the well is economic, the method is justified. f)

Waste Water Disposal

The primary waste water consideration when looking at stiff foam is the effect of the viscosifier on disposal of the water. This could make reinjection of the water impossible or could have no effect on disposal costs. This must be examined well in advance to compare systems, consider recycling and establish what disposal method will be appropriate. If recycling is used, the fluid viscosity is another tool to establish the dilution rates. g)

Formation Damage

If an underbalanced condition is maintained, formation damage is not a concern. However, if the formation is ever overbalanced, the viscosified fluid may have more damage potential than a simple surfactant system. If the viscosifier acts as a bridging agent (long chain polymer), it may build a filter cake and reduce formation damage. Test the fluid loss and filter cake to determine the results of occasional overbalanced conditions.

7.

Summary

Stiff foam systems offer an additional tool to successfully drill underbalanced when conditions are not conducive to other methods of underbalanced drilling. a)

Advantages

In cases where hole cleaning is a concern, such as large diameter hole, stiff foams may be a solution. In cases of water influx or contamination of the foam system, stiff foam systems have advantages. b)

Disadvantages

If run at very high qualities, stiff foams can be susceptible to collapse due to gas influx. However, they can be adjusted and compensated. The liquid fraction is more expensive than for stable foams, but stiff foams require less liquid. Stiff foams can be very difficult to break at surface. A stiff foam is more likely to form stable emulsions with produced fluids than a stable foam. c)

Design Criteria

Large diameter holes with anticipated hole cleaning problems, water influx, or contamination problems are situations where stiff foam drilling should be considered.

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GASIFIED LIQUIDS

Gasified or aerated liquids are one of the oldest underbalanced drilling techniques and are the most common in Canada and many other parts of the world. The ability to vary the gas fraction and change the mud weight has significant advantages over air, mist, or foam systems which allow very little control over fluid density. Gasified liquid technology was primarily developed to combat lost circulation problems. It has become an effective underbalance technique with the development of computer programs to calculate bottom hole pressure. These programs allow a controlled drawdown to be maintained to avoid formation damage from overbalanced fluid invasion or from fines migration due to uncontrolled flowrates. Gasified liquid drilling normally uses effective fluid densities in the 4 to 7 ppg range. The base liquid is usually unviscosified water or crude aerated with nitrogen, air, or even natural gas. Since the primary component of the system is liquid, it is more likely that nitrogen is economical and also eliminates the inherent problems of air/water mixtures.

1.

Gasification Techniques

Gasification of the liquid is accomplished either at surface through the drillpipe, or downhole via several possible flowpaths. Drillpipe injection allows for the lowest bottom hole pressures. Annular injection will normally provide the desired reduction of BHP at the cost of increased gas injection but allows for the utilization of MWD mud pulse telemetry. If possible, some form of annular injection is usually desirable. a)

Drill Pipe Injection

The gas phase is added at surface to the drilling fluid. This is the deepest gas injection and lowest BHP but doesn’t allow for continuous MWD operation. The initial cost is lower as no additional equipment is required and the required gas volume is less. The cost savings must be contrasted with longer connection times, from drill pipe bleeding, less reliable BHP information, and limited ability to use MWD. b)

Annular gas Injection

The gas phase is added downhole. Annular gas injection allows for accurate BHP calculations and MWD. Several paths are possible for annular gas injection. In most cases the cost will be higher for equipment and gas volumes will be higher. Some cost savings will occur in operations by elimination of bleed time. Gas injection can continue during connections and trips which ensures that underbalance conditions can be maintained at all times when drilling sensitive formations.

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Parasitic String A parasitic string, either jointed or coiled tubing, can be run and cemented behind the casing string with an injection sub close to the casing shoe. This option involves additional equipment cost and additional operational time and the pipe is not recoverable. Parasitic Casing A parasitic casing string can be temporarily hung off inside the intermediate casing. This casing is recoverable but involves some hang off equipment. The problems associated with parasitic casing are restricted hole diameter and wellhead height. Through Completion If gas lift exists, the lift system can be used with no additional equipment cost. If available, this is the best option because it doesn’t involve extra cost, reduction in hole size, or additional wellhead height. The lift system could be operated on natural gas, nitrogen, or air.

2.

Liquid Phase

The liquid phase in gasified liquid drilling is normally water, brine, diesel, crude, or condensate. Water influx makes it uneconomic to use muds due to the high cost of reconditioning the mud system. The liquid chosen should be as non-damaging as possible to avoid formation damage when overbalance conditions occur. Viscosified fluids are normally avoided due to emulsion and foaming problems at surface as well as additional potential for formation damage. The primary fluid related problems to plan for and watch for are emulsions of formation fluid and drilling fluid, foaming of the returns, monitoring additives, such as KCl, and separation of the 3 phase system at surface. These problems can be handled with a minimum of planning. All of these problems are exacerbated by the addition of viscosifying agents.

3.

Gas Phase

The gas phase can be air, nitrogen, or natural gas. Air is inexpensive but carries the risk of corrosion problems and in horizontal wells, downhole fires. In a gas lift well, natural gas may be a viable option if surface facilities are available to handle the gas. The best option, if economic, is cryogenic nitrogen. Utilizing air as the gas phase carries all of the potential problems discussed earlier. Corrosion and combustion must be considered as well as economics. Membrane produced N2 contains ≤5% oxygen so is not a downhole combustion problem but is a corrosion problem. Natural gas may be a fire hazard, but if the well will be producing gas, it may be the best option with the addition of gas busters and/or separators.

4.

Equipment Selection

a)

Gas Injection System

Gas equipment will be specified as discussed in earlier sections. Once the gas is chosen, refer to the air/nitrogen/natural gas drilling section of the manual. b)

Parasitic Tubing String

A parasitic tubing string can be jointed pipe or coiled tubing. The string should be clamped to the casing to ensure integrity when the casing is run and cemented.

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Parasitic Casing string

The possible hole size that can be drilled through the parasitic casing should be considered as well as the hang-off method and additional wellhead height necessary to hang the string. d)

Liquid Injection

The rig mud system should handle the liquid injection easily. Check the minimum pump rates required vs. the rig pump minimum capacity. The low pump rates may require smaller liners and plungers. e)

Drill String and BHA

Standard drillstring components are applicable. Consideration should be given to BHA geometry to allow for stripping in and out of the well. Drillstring floats or hydrostatic control valves (HCV) are required as in all underbalanced drilling. The requirement for a surface drillstring float depends on the gas injection point. If pure liquid is in the drill pipe a surface float is not necessary. If liquid is in the drillstring a HCV may be required to hold the column of fluid and not allow air into the drillpipe. The HCV is a spring loaded check valve that holds enough backpressure to stop the fluid in the drillpipe from falling and allowing air into the drillstring. Without a HCV there is a danger of a downhole fire and the MWD cannot communicate until the air is circulated past the telemetry cartridge. f)

BOP Stack

BOP requirements will depend on local regulations and operational considerations. With no anticipated high pressures, a rotating head and standard BOP stack may be sufficient. At higher pressures a RBOP and the capability to strip ram to ram may be necessary. g)

Return System Configuration

Low Pressure/Limited Production Returns can be routed from the rotating head to a flare pit and the settled water transferred back to the pits. The choke line can also be routed to the same pit. If an expensive fluid is used, either brine or mud, the returns can flow to a gas buster. The liquid is then routed to the shakers and the gas to the flare pit.

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High Production and/ or High Pressure If high production and/or high pressures are anticipated, an ESD will be necessary on the return line and a gas buster or, in the case of oil or condensate production, oil/water separation will be required. This system could vary from a simple skimmer to a full closed system with 3 phase separation. Closed systems will be discussed in a later section of the manual. Surge Tank When using aerated liquids as the drilling medium, a surge tank should be utilized, thereby preventing the air from blowing water or mud out of the system. This tank can also assist in the separation process. Downhole pressures and surging can be further controlled by placing a back pressure control choke at the surge tank. h)

Instrumentation

The instrumentation required for gasified liquid drilling is dependent on the primary purpose of choosing this method. If lost circulation is the primary problem and formation damage is not a concern, extra expense for sophisticated monitoring systems is probably not justified and the instrumentation used for air drilling is sufficient. If formation damage is critical, direct downhole pressure measurement may be an option with MWD or a sophisticated surface monitoring system. Feeding measurements to a computer model may be utilized to calculate BHP, flow conditions and influx. There are several systems available that monitor all available surface information (including returns composition) and model the complete circulating system (including calculations of influx rates). The more data that is incorporated into the model, the more reliable the BHP will be.

5.

Operating Procedures

a)

Controlling Bottom Hole Pressure

BHP is controlled by varying the gas and liquid injection rates. If BHP is critical, MWD and/or a surface computer model is necessary. If the BHP is friction controlled, an increase in gas will increase the BHP. If the BHP is hydrostatically controlled, the same change will act the opposite. Even with live BHP a computer model may be necessary to determine new gas and liquid injection rates to adjust the BHP. b)

Making Connections

Making connections varies depending on how critical maintaining underbalance is and what type of gas injection is being used. With annular injection, the gas may continue and the drill pipe may be full of fluid. Connections are rapid and simple. With drillstring injection, the gas must be stopped causing the BHP to increase. If not critical, the drill pipe can be filled with fluid to the upper float, bled quickly, and connections will be faster. However, this will create a BHP spike as the fluid is circulated around. The string can be displaced to gas before a connection. This will also reduce bleed time and result in a lower maximum BHP than displacing fluid to the top float. c)

Trips

Tripping the drillstring will depend heavily on the amount and type of flow from the well. In most cases the pipe will be stripped from the hole as in other underbalanced drilling and may need to be staged back in to bottom. Refer to earlier discussions on tripping.

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Limitations

The limitations inherent to gasified liquid drilling are high formation pressures or productivity, wellbore instability, pressure control, produced water, corrosion, and penetration rate. In all of these limitations except penetration rate, gasified liquids are better suited to handle the problems than the other underbalanced drilling methods discussed. a)

Formation Pressures and Productivity

Gasified liquids provide the highest BHP of the methods discussed so far and are the most likely to be able to drill high pressure or high flowrate formations without reaching the production limits of the surface equipment. In most cases the surface pressure and flowrates will be within tolerable limits. b)

Wellbore Instability

The higher BHP exerted by gasified liquids provides support for mechanical instability in the wellbore and allows the successful drilling of less competent formations than other forms of underbalanced drilling. Mechanical instability may be a problem when drilling through overpressured shales to reach depleted reservoirs. Water sensitive shales are more susceptible to swelling using a gasified water than a lighter or water free system. Gasified hydrocarbon fluids or shale inhibitors will control this problem. c)

Pressure Control

Controlling BHP is difficult with a gasified liquid due to unstable conditions caused by connections and trips. Careful planning and the ability to control fluid densities through a significant range can offset or eliminate problems with BHP control that cause transient overbalance or excessive underbalanced conditions. Establishing a maximum and minimum allowable BHP provides a framework to plan operations to reach the goals of the drilling program. d)

Produced Water

Produced water can be tolerated in large amounts by a gasified liquid system. Two potential problems involving water influx are hole cleaning below the influx and ECD variations in the wellbore. If a large water influx requires increased gas injection and/or decreased fluid injection, problems may be encountered cleaning the hole below the influx. This could require increasing liquid viscosity to lift cuttings and cause problems with emulsions, foaming, and/or separation problems at surface. A situation can arise where the ECD on bottom, where the gas is compressed, can cause lost returns while at the same time a shallower zone is flowing, due to lower ECD caused by the expanded gas lightening the fluid uphole. In some cases circulation cannot be established under these conditions even with dry air injection. The only options are to run casing or drill with no returns as described in Section III.I “Mudcap Drilling." e)

Gravity Invasion

While horizontal drilling with gasified liquids, or flow drilling, it is possible to lose fluid to the formation while the well is flowing. Gravity invasion is the process of liquid running into the macroporosity on the low side of the hole while the well is flowing. This is demonstrated in the following diagram.

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Gravity Invasion

No Invasion at Top of Hole

Wellbore

Drill Pipe

Water

Small Fracture High Velocity No Invasion

Figure 3-8 Gravity Invasion f)

Corrosion

As in any water/air system, corrosion can be a major problem. If it is impractical to use cryogenic N2 as the gas phase, then apply the same corrosion precautions as for mist or foam drilling. g)

Penetration Rates

Gasified liquid drilling will typically produce penetration rates higher than mud drilling and lower than gas, mist, or foam drilling. The penetration rate is usually related to pressure; hence, average fluid density will be the controlling factor. In weak formations, the overall penetration rate is often not the achievable rate but the sustainable rate. In this case there will be little variation between any systems from air to mud. In some areas it is not possible to run maximum bit weight in the surface hole and the penetration rate is limited by cuttings transport either in the wellbore or the surface equipment. In this case penetration rates are similar regardless of the drilling system utilized.

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Summary

Gasified liquid drilling is another tool that can be tailored to specific requirements of a well. a)

b)

c)

Advantages •

Allows underbalance to be designed rather than set by the drilling method by using variable fluid densities.

•

Is much more tolerant of pressure and influx than other methods discussed.

•

Provides much more mechanical support for the wellbore than other methods discussed.

Disadvantages •

Does not provide as much underbalance as other methods discussed.

•

There is a smaller gain in penetration rates.

•

Can create corrosion problems.

Design Criteria

In wells with high pressure or high influx rates gasified liquid provides more control of BHP. In weak formations additional wellbore stability is achieved by the increased effective density of the system. With annular injection, standard MWD technology can be applied for directional control and pressure monitoring.

H.

FLOW DRILLING

All methods of underbalanced drilling are technically “flow drilling." This terminology is used to describe drilling underbalanced with a liquid system rather than a drilling fluid with a gas fraction. In some cases the formation pressure is higher than the fluid pumped, and the well is in a “flow” pressure regime from the lack of hydrostatic pressure exerted by the drilling fluid. In other cases the fluid is above kill weight and hydrocarbon flow from the formation underbalances the well on the annulus side of the flow path. In either case, pumping liquid at surface and maintaining underbalanced conditions downhole is referred to as flow drilling.

1.

Creation Of Underbalanced Condition

In some cases, where the formation pressure gradient is above an available fluid gradient, production casing is set above the target interval and drilled out with a mud weight below the formation pressure. This is often used for underbalanced horizontal drilling to eliminate formation damage during the long exposure of drilling fluid to the horizontal section. When the drilling fluid is above the formation pressure gradient, nitrogen can be used to initiate flow from the reservoir. Once the well starts flowing, the N2 is stopped and the influx maintains the underbalanced conditions. A method under development for an incompressible lightened fluid is the addition of hollow glass spheres to the drilling fluid. An 8.8 ppg polymer mud can be reduced to ~6.5 ppg with the addition of 40% glass spheres. At present this method is probably not economical, but it does provide a future path for low weight, incompressible fluids.

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In some fractured reservoirs, the fracture system will cause lost returns when the reservoir is penetrated. As the hydrostatic falls, the well will start producing oil and gas and come on production. The Pearsall field in the Austin Chalk is an example where this method is used to flow drill. It is also possible to kick off the well after penetrating the top of a formation using gas and then flow drill the remainder of the well.

2.

Drilling Fluids

The fluids selected must maintain the wellbore pressures between zero underbalance or balanced pore pressure and minimum pressure allowed by the wellbore stability. Normally, non-damaging non-viscosified fluids are used to avoid damage from periodic overbalanced conditions and to reduce surface handling problems caused by emulsions, foams, and poor or slow separation. In some cases, like large hole or long horizontal sections, it may not be possible to clean the hole properly with non-viscosified fluids. One consideration that can preclude choosing hydrocarbon based fluids is their ability to carry dissolved gas. In cases where gas is dissolved in fluid, large pressure surges can be experienced because the gas does not expand slowly as bubbles, like it does in water. The gas breaks out of the liquid suddenly and expands very rapidly, usually close to surface.

3.

Surface Equipment

To safely flow drill, the surface equipment must be designed to handle the pressures and rates experienced during the job and must be in good working order. You will be living in a well control situation and shortcuts in inspecting, repairing, or testing the surface equipment can be fatal. The operations of the surface equipment is the difference between a successful job and a catastrophic failure. a)

BOP Stack

A standard BOP stack with the addition of a rotating head (RH) or rotating BOP (RBOP) is used in many flow drill operations. From the bottom, double outlet spool, blind rams, pipe rams, annular ram, double outlet spool, and RBOP is a standard configuration. The addition of pipe rams below the blinds and an additional double outlet spool between the blinds and the annular are frequently added for more flexibility and redundancy. b)

Rotating Head vs. RBOP

The rotating head has been used very successfully on many wells but has limitations and drawbacks. The RH tends to develop low pressure leaks with minor amounts of wear due to the design of the element. API does not recognize the RH as a BOP component and companies do not rate them with regard to pressure containment. There is no way to monitor the wear on the RH and the life expectancy cannot be predicted. The rotating BOP is a pressure rated BOP with a 2 level closing system that prevents catastrophic failure when used within rated limits. They are commonly available (with API approval) up to 1500 psi working/2000 psi stationary and a 2500 psi/5000 psi RBOP is available.

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Choke Manifold

A 4” dual choke manifold with a bypass is usually sufficient for flow drilling operations. As long as plugged or cut out chokes can be isolated and repaired or replaced, most large choke manifolds are useable. Items that need to be considered are true open flow area, which varies for the same size chokes from different companies, and if high flow or long drilling duration through the choke are anticipated, all 90’s and flow tee’s should be targeted with lead. d)

Mud/Gas Separator

The requirement for a mud/gas separator varies tremendously with well conditions. On a low productivity low GOR well, a gas buster is sufficient. On a high gas rate well with H2S, a closed system including 3 phase multi-stage separation may be necessary. A 6’ diameter by 12’ tall, or larger, atmospheric mud/gas separator with a 6” to 12” flare line and large liquid dumps will handle most flow drill jobs. The flare line should be either run to a large flare pit or be an adjustable height stack capable of safely flaring all potential gas returns. Note that some flow drill flare stacks are 100’ tall. The following diagram, Figure 3-9, is a surface system for 3 phase flow with no H2S in the gas.

Gas lines Flare Stack Fluid Lines Optional

RBOP

In-Line

GAS BUSTER

Heater Shale Shaker

Oil Tank

Skimmer Tank

Fig. 3-9 Flow Drilling Surface System

e)

BOP

Choke Manifold

Mud Tank

Mud Pump

Nitrogen Unit

Oil/Water Separation and Storage

Oil water separation without H2S is normally accomplished in an open skimmer system with the water being returned to the rig pits. In high flow situations the returns may go through a 3 phase separator and have a skimmer system to clean up the water before sending it back to the pits. The oil collected is either transferred directly to an existing production system or pumped to a storage tank for transportation to a facility.

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Operating Procedures

The primary difference in operating procedures between normal (overbalanced) drilling and flow drilling is that control of the well is maintained at surface rather than at the formation. The objectives are to maintain control of the well while avoiding formation damage, differential sticking, and lost circulation. To achieve these goals it is desirable to design the operations to have as few interruptions as possible in circulating the well while holding positive pressure differential from the formation to the wellbore. All pressure limitations must be firmly established during planning the well and contingencies written for specific cases to eliminate any delays dealing with changes that are observed while drilling. The drilling supervisor should know in advance what action will be required at given surface conditions. The options of changing fluid densities, varying circulating rates, and imposing surface pressures should all be clearly defined before spudding the well. Initially the returns will be routed directly to the shaker and the annulus will be maintained at atmospheric pressure. When formation fluid inflow starts, the returns will be directed through the choke manifold then to the surface separation system. The separation system should be sized to handle any instantaneous flowrates from the well. These instantaneous rates, or slug flow can be much higher than the potential of the well for continuous flow. If the well approaches the maximum surface system rate, it will have to be choked back and changes in fluid density or drilling style made to reduce the flowrate. Connections are similar to any underbalanced drilling method. Any drillpipe pressure is bled down to the top float and the connection made. Tripping depends on the observed and predicted surface pressures. If the pressure is too high or is expected to rise to an intolerable level during the trip, the annulus can be slugged with a heavier fluid. If annulus pressures rise toward the safe limit during the trip, this can be repeated. Before logging or tripping, it may be desirable to circulate the well to a lower amount of underbalance to avoid repeatedly pumping the annulus and possibly overbalancing the formation. Be aware that with the formation balanced or overbalanced the rise of gas will still increase the surface pressures and create a situation where it is natural to pump more kill weight fluid even after the formation is overbalanced. These conditions have occurred in many cases where the projected productivity increase was not achieved even though “the well was never overbalanced." Surface pressure alone does not mean that the formation is underbalanced! Once the well has been drilled underbalanced, logging and completion operations should be performed underbalanced. The casing must be run underbalanced; the completion performed underbalanced; and the well should be perforated with as much underbalance as is reasonable.

5.

Limitations

Limitations of flow drilling that can cause prospects to be removed from the flow drilling candidate list include high annular pressures, undefined formation pressures, and/or wellbore instability. a)

High Annular Pressures

High annular pressures, whether during a trip or caused by having to choke back the well while drilling, must be controlled within the specified limits of the job. The first step is to decide if there is an error in the calculated fluid densities or in the drilling method. It may be necessary to control drill the pay zone to avoid having the gas/liquid ratio increase too rapidly as drill gas lightens the column, more than projected, and increases influx. The well should be choked back and circulated from close to bottom. Then determine whether to increase the annular pressure, by choking, or increase the fluid density to maintain desired drawdown. Carefully consider the project’s goals when deterring the subsequent recourse. Circulating time is not significant when compared to damaging the well by taking the wrong step before fully understanding the problem. Excessive surface choking can cause breakdown of shallower formations.

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Uncertain Formation Pressures

Flow drilling is poorly suited to areas where the formation pressures throughout the wellbore are not known sufficiently or where there is a transition zone in the openhole section. When air drilling, the wellbore is always underbalanced. Drilling with near or above gradient fluid, however, it is easy to be overbalanced and underbalanced in the same wellbore. Several instances happen and are worth discussing. Example 1: A well is flow drilled through a depleted zone and into a gas sand. The depleted upper zone takes all the fluid that is pumped and everything the gas sand contributes. This is an underground blowout. If drilled with mud, the depleted zone would undoubtedly have had a good filter cake, the gas sand would have been overbalanced, and the well would not likely have encountered these problems. Example 2: A well is flow drilled through a water sand above the target in an infill program. The previous overbalance drilled wells did not see the water sand, but it is now flowing because of the low weight fluid in the hole. The target is penetrated and the returns slowly stop because the combined flowrate is too high for the drill gas to lighten the fluid, and hence, underbalance the well. Nitrogen is used to kick off the well, without knowing that large water volumes are flowing into, and damaging, the target zone. The well is kicked off and drilled to TD. After the completion, production rates are much lower than expected for drilling the well underbalance. c)

Wellbore Instability

Flow drilling, in most cases, provides more borehole support than most underbalanced drilling methods. Drilling weaker formations is more viable than with other systems. Unconsolidated or very weak formations can readily produce more solids than the producing interval produces fluids, and so borehole sloughing, erosion, or collapse is always a concern. If problem zones appear in the candidate, either casing off the zone before flow drilling commences or drilling overbalanced may be necessary.

6.

Summary

Flow drilling is another practical method of underbalanced drilling. The advantages and disadvantages should be considered in the design criteria, as described below. a)

Advantages

Flow drilling allows for underbalanced drilling without the equipment or problems associated with gas compression and handling. It is conducive to MWD use and provides a very flexible system for achieving a set amount of underbalance while drilling. In most cases, flow drilling exhibits no higher corrosion rates than overbalanced drilling. Additionally, flow drilling eliminates downhole combustion problems associated with air drilling.

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Disadvantages

As in all underbalanced drilling, well control, borehole stability, and returns handling can become problems and must be studied. Appropriate steps can then be taken to reduce the problems encountered while drilling. Hole cleaning in large holes or horizontal sections can be a problem and require viscosifying agents. The associated problems, emulsions, foam, and separation, will have to be considered and economically factored into the decision of whether or not to flow drill the well. c)

Design Criteria

Areas that exhibit lost circulation problems, significant formation damage, and/or wellbore instability that doesn’t allow for other types of underbalanced drilling are good candidates for flow drilling. Any well that appears to be suited for underbalanced drilling but falls short of the criteria for the other methods should be considered for flow drilling.

I.

MUDCAP DRILLING

Mudcap drilling is a technique that has been developed to continue drilling when flow drilling develops two conditions. First, surface pressures or rates that are beyond the safe operating limits of the RBOP or surface facilities, and second, kill weight fluid results in lost circulation. This situation does not allow for a reasonable response to continue normal drilling. Thus, mudcap drilling is an alternative method.

1.

Overview

This technique is a method of lost circulation and well control that could allow the completion of a well that is not progressing as planned. This is not technically “flow drilling” because the well doesn’t flow to surface, but the equipment used for flow drilling is applicable and it could be a choice in certain circumstances while flow drilling. One example of this situation would be a downhole blowout where circulation is lost below a productive interval and the hydrostatic necessary to limit the flowrate is lost. This leads to uncontrolled flow. Hence there is lost circulation and uncontrolled flow concurrently. This situation can occur during mud drilling but usually leads to massive lost circulation and kill operations, and drilling is not continued. In cases where lost circulation and kicks are expected, and the H2S levels are too high to safely plan on having periodic well control situations, mudcap drilling may be planned to avoid bringing H2S to surface and endangering the rig crew. Switching to mudcap drilling as soon as the returns are lost stops the majority of formation fluids from being in the wellbore until the well is completed and is no longer a major safety concern. The basic idea is to pump fluid down the backside to reduce annulus pressure and then drill with water or brine with the return line closed. Where the cuttings go is often speculated, but the method seems to work in fractured reservoirs and lost circulation zones. In one fractured carbonate reservoir, mudcap drilling is actually a planned drilling system. See the GRI Underbalanced Drilling Manual for specifics on this well. In most cases, mudcap drilling is used when no other alternatives exist.

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2.

Underbalanced Drilling Shortcourse

Summary

As questionable as mudcap drilling appears to drilling a successful well, it has been used in fractured carbonates successfully using the design criteria described below. It has also been successfully used in underground blowout situations, as described above. Like any unusual drilling technique there is limited applicability. a)

Advantages

In an extremely productive interval there is often a very small pressure change between lost circulation and flow. If mud weights are raised, there are lost returns, and if mud weights are lowered, the well takes a kick. With high reservoir pressure, it may be uncontrollable as a flow drilled well with RBOP limitations. Mudcap drilling may allow the well to be drilled and cased where any other system would require abandoning the prospect. b)

Disadvantages

This method of drilling does not provide cuttings or much reliable formation data. Furthermore, the risk is high for sticking pipe. c)

Design Criteria

There is a limited number of mudcap drilling candidates because the basic technique normally does not achieve the goals of the drilling program. A prospect with the following criteria may be a good candidate for mudcap drilling. Even in this case it is unlikely that injecting huge volumes of fluid and all the cuttings from the lower section of the hole would result in less formation damage. This has been the case, however, in a fractured carbonate where the injected solids were acid soluble and in or where abandonment was the only other alternative. •

High Pressure

•

Sour Production

•

Lost Circulation

•

Formation Damage from Mud

•

Slim Hole

Mud cap drilling is best applied to wells that have:

J.

•

Surface pressures in excess of 2000 psi,

•

Sour gas production,

•

Small diameter wellbores.

SNUB DRILLING

Snub drilling is an underbalanced drilling operation which uses a snubbing unit as the pressure control system. The snubbing unit is much better equipped to work pipe under pressure and allows for drilling operations to be performed with much higher surface pressures than with a drilling rig.

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1.

Page 69

Overview

Snub drilling is an option where underbalanced drilling is desirable but the well considerations preclude utilizing a rig as the primary drilling and pressure control system. The snubbing BOP system can safely work pipe up to 10,000 psi and the snubbing crew has more experience and training than a rig crew for high pressures. The additional expense involved in using this equipment is more than justified by the additional safety provided by the equipment and training. The snubbing unit can easily strip in and out of the hole as long as the pressures are low. If high surface pressures are encountered, they have additional capacity to strip ram to ram and can snub the pipe into the hole when the pipe weight is insufficient to overcome the upward pressure force. In high pressure operations, a great concern is blowing the pipe out of the hole when the pressure overcomes the weight of the pipe or being unable to run in against the pressure. Killing the well can damage the formation and nullify any gains previously made drilling underbalanced. A snubbing unit allows the well to be flowed or shut in during connections and trips and eliminates one potential cause of formation damage. When a drilling rig runs casing underbalanced, it is normal to partially kill the well before starting the casing job. During the course of tripping and running casing it is very likely that the formation will see some overbalance at some time, for example by surge pressures or excessive kill fluid as gas bubbles rise. Snubbing the casing in will help to avoid this situation and could make a large difference in the final well productivity.

2.

Summary

A snubbing unit has much better pressure control than a rig. This can have a large impact on personnel and rig safety as well as a large impact on final well performance. Using a snubbing unit allows some decisions to be made based on what is best for the well, by reducing the requirement to contrast all decisions with limited excess capacity at surface for additional pressure. Many wells have been damaged by controlling the surface pressure too much to maintain a safe margin below the capacity of the surface equipment. By increasing the safe pressure handling capacity by 3 to 6 times it may become possible to concentrate on maintaining an underbalanced condition and still operate well below any pressure restrictions. Additional well production will significantly justify the extra expense. a)

Advantages

Using a snubbing unit has the following advantages: •

Improves rig safety both with equipment and training,

•

Reduces the chances of formation damage,

•

Allows pipe to be run in and out of the well under more pressure,

•

Allows casing to be run underbalanced without the formation being overbalanced at some point during the casing job.

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Underbalanced Drilling Shortcourse

Disadvantages

A snubbing unit is more expensive per day and is slower. The added expense must be offset by safety issues and well economics. The useable drillpipe size can be limited as well as available torque for drilling. These items are not normally insurmountable and a variety of options exist to increase performance. Note that snubbing units are available that can handle up to 10-3/4” casing. c)

Design Criteria

The situations where a snubbing unit should be considered are

K.

•

Very high annular pressures,

•

Vertical fractures,

•

Severe lost circulation,

•

High pressure stripping operations,

•

Expensive drilling fluids,

•

Surface equipment limitations,

•

Personnel and rig safety considerations.

CLOSED SYSTEMS

Many underbalanced drilling operations utilize an open return system that is adapted from standard rig equipment with only the necessary additions to permit operations to proceed. In some cases where a production system is in place, and the projected cuttings volume is very small, the returns are directed into the production system, either directly or through a choke manifold. An example of this style of drilling is reentry slimhole kickouts with coiled tubing. Closed systems combine the advantages of both methods of handling returns. In a closed system all fluids are fully contained until the drilling fluid is pumped back to the pits. The gas can be flared, the oil collected for sales, and any H2S in the system is safely contained. If the oxygen content of the returns can be maintained below the LEL, usually about 8%, the closed system provides the safest operation, the most control, and the best information on the well. Figure 3-10 is a 4 phase closed system. Optional N2 injection and heating of the returns are shown in addition to the standard system.

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Gas lines Flare Stack Fluid Lines Optional

RBOP

In-Line

4 Phase Separator

Heater Production Tank

BOP

Choke Manifold

Mud Tank

Cuttings Storage

Mud Pump

Fig. 3-10 Underbalanced Drilling Closed System

1.

Equipment Selection

a)

Return Line

Nitrogen Unit

The return line should be large diameter and allow for the following: •

Divert to shakers, separator, or directly to flare pit;

•

Flow through rig choke manifold or through larger drilling choke manifold;

•

Be equipped with ESD valve and manual shut-in valve;

•

Have same pressure rating as BOP upstream of ESD;

•

Be equipped with a sample catcher;

•

Have lead targeted tee’s and 90’s where applicable.

The return line may contain high pressure, 4 phase, high velocity flow and must be designed to handle more than the projected rates. It is a large choke line, not a return line in the normal sense of drilling, and must be designed and maintained as such. This is a critical link to the overall safety of the system. b)

Flow Control Manifold

A flow control manifold should be used in addition to the rig choke manifold. This manifold is similar but with larger valves and piping. The flow control manifold is the primary flow path with the rig chokes as a back up system. This is a good location for the addition of a sample catcher.

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Underbalanced Drilling Shortcourse

Cuttings Filter

The cuttings filter is a pressurized vessel designed to drop out the majority of the cuttings into a removal system, like a moyno pump, then pass the gas, oil, and water to a separator. This allows the use of a 3 phase separator for primary separation. A 4 phase separator, if available, takes the place of the cuttings filter and the 3 phase separator. d)

Heater

Produced gas in the presence of water can form gas hydrates. This normally occurs at a pressure drop where the gas expansion refrigerates the flow. The formation of hydrates can plug lines and valves downstream of a primary pressure control device and cause pressures to exceed the rating of the downstream equipment. The pressure rating specification of equipment and lines is usually different across a choke. Hydrate plugging downstream of the choke can quickly expose the low pressure side of the choke to full choke pressures. There are very good computer programs to predict the formation of hydrates. If any chance exists for the formation of hydrates there should be an in-line heater installed to raise the flowing temperature enough to prevent the hydrates. At low flowing pressures it will probably not be necessary to install the heater.

2.

Operational Procedures

Operating a closed system requires more monitoring than an open system. All pressures and levels must be maintained for safe efficient operations. Plugging of equipment is more likely than in an open system and more difficult to correct. The items unique to closed system drilling the require special attention are •

Separator levels must be monitored at all times;

•

Liquid and solid discharges should be recorded to provide well information;

•

Separator pressure must be maintained to achieve proper separation, but the separator must be kept below is rated working pressure;

•

The flare line can be used to regulate the separator pressure with a back pressure valve;

•

Any plugging should be immediately corrected, while flowing through a backup if possible or with the well shut in;

•

The flare must be lit or have a pilot light at all times;

•

Wall thickness should be monitored in critical flow areas;

•

If injecting any O2, the separator must be monitored for LEL and purged with N2 when necessary.

This may seem like a sizable job but the closed system operators are trained and experienced at monitoring all of the above.

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3.

Page 73

Limitations

The limitations of closed system drilling are pressure, gas composition in the flow stream, availability of people and equipment, and costs. a)

High Surface Pressures

Care should be taken to ensure that the surface system will be capable of handling the pressures and flowrates that will be experienced during drilling and completion operations. The possibility of plugging must be considered and appropriate pressure relief installed to a pit or tank as conditions warrant. b)

Drilling Fluid Gases

If air is to be a component of the drilling fluid, prejob investigation of explosive limits with mixtures that closely resemble actual conditions should be performed. The accepted lower limit for flammable hydrocarbon and oxygen mixtures is 8% O2 but lab tests have maintained combustion at 6%. H2S can lower the O2 level required for combustion. Moreover, hydrocarbon composition has an effect on combustion. c)

Equipment and Personnel Availability

Before deciding to drill underbalanced, investigate equipment and crew availability. The equipment is more common in Canada than the U.S. and the utilization is growing. It could be difficult to find equipment and crews in this fairly new and expanding market. The utilization is a good indicator that operators are pleased with the results of the closed systems. d)

Operating Cost

Additional costs must be carefully considered. There is a large difference in required crew levels and in operating and repair costs depending on the system contracted. A fully automated system with targeted tee’s and 90’s may only require one operator and require very little repairs. A much cheaper unit may require several operators and periodically shut down drilling for repairs and washouts. The apparent day cost is higher during closed system drilling. The project cost can be higher or lower depending on savings from pit construction and reclamation, location size, surface damages, etc. Operationally, the closed system can reduce unproductive time by allowing for less circulating time controlling the well within a limited pressure and flow window. Overall cost has been shown to be lower in many cases.

4.

Summary

Closed system underbalanced drilling has many benefits to the operator. Some of the benefits can be directly analyzed on a cost basis and some are difficult to quantify. Any improvement in safety and environmental protection has a risk value that may be definable but also carries an indirect benefit in public image. In some cases the improved government and public relations from safe and environmentally friendly operations can far outweigh the additional costs of closed system drilling. In other cases these intangible benefits come as a dividend with a less costly and more efficient operation. .

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Underbalanced Drilling Shortcourse

Advantages

The advantages of closed system drilling are

b)

•

Can eliminate reserve pit costs (O & G Journal May 27,’96), or reduce the size and reclamation costs of the pits;

•

Safer than open system, if oxygen is not introduced into the system;

•

Allows accurate measurement of gas, liquid, and solids from the well;

•

More environmentally acceptable than a reserve pit;

•

Creates a smaller footprint, which may be critical in reentry or offshore drilling;

•

Allows for production testing without additional rig up;

•

May have an image benefit due to improved safety and environmental concerns.

Disadvantages

The primary disadvantages in closed system drilling are

c)

L.

•

Daily equipment and operating costs are higher. Note that pit construction, location reclamation, and drilling efficiency can more than offset this cost;

•

Is not safe if oxygen is present in the drilling fluid, as explosive limits can be reached in surface vessels.

Design Criteria •

In wells where H2S is anticipated,

•

High productivity or high pressure wells,

•

Limited workspace,

•

The need for well information during and after drilling,

•

When pit construction and reclamation costs are high,

•

When safety concerns dictate,

•

When environmental considerations are critical.

COILED TUBING DRILLING

Coiled tubing drilling is progressing as a more viable alternative to jointed pipe drilling as technology, larger pipe, and more powerful equipment is being introduced. The ability to monitor pipe life, the availability of pipe up to 4-1/2”, and the introduction of injector heads with 150,000# pull capacity is allowing operations that were not possible a few years ago. Coiled tubing can be used as a free standing underbalanced drilling unit, or can be used as a rig assist unit. It is particularly well adapted to drilling with high surface pressures. The lack of tool joint connections allows for continuous underbalanced conditions while drilling and while tripping. The lack of

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Page 75

rotation creates larger cuttings for geophysical examination and use wireline readout MWD. There have been many successful short radius, 50°/100, horizontal wells drilled with CT and new drilling systems are being developed to refine and improve operations. Coiled tubing rig assist operations are similar to rigless operations, that is coiled tubing unit only, with the added benefits of having a rig. This discussion will concentrate on rigless operations to avoid the confusion of describing the differences with or without the rig. It should not be difficult to pick out the portion of operations that would exist in rig assist operations. Coiled tubing drilling operations are expensive, particularly with steerable surface readout MWD, but can be equivalent or less than rig operations in the same field and conditions. The costs are typically higher so justification is normally based on well considerations or situations that eliminate rig operations, such as space, height, safety, and environment.

1.

Equipment Selection

a)

Coiled Tubing Unit

Consideration of a coiled tubing unit (CTU) for drilling operations must start with pipe size. Once the pipe size has been determined and the well depth is known, the injector head pull capacity can be determined. Inquiries will find availability and cost for the required size unit. b)

Special Drilling Equipment

The special equipment required for a stand alone CT drilling unit is •

A work floor with capacity to handle BHA components,

•

Power tongs to make up/break out the BHA,

•

Some system to run and pull pipe. In some cases this can be accomplished with a large crane and the power tongs. In some cases it is economical to use a pulling unit for pipe handling and CTU for drilling.

CTU contractors are building more drilling units and if not available will frequently add the required equipment to an existing unit to increase its capacity for work. Some composite units are available that are workover rig based CT drilling units. c)

Pumping Equipment

On some slimhole reentry projects the CTU pumps will be sufficient. Large pumping equipment is not usually part of the CTU and must be specified based on the well program requirements. d)

Returns System

CTU is well adapted to a full closed system. Whatever returns system is chosen, there may be additional costs for equipment that would be normally supplied with a rig.

2.

Operational Procedures

Coil tubing does not rotate. This is the driving force behind most differences between coil tubing and rotary drilling. All CT drilling is “slide drilling.” This creates some changes in wellbore mechanics that require compensation. The tool joints on a drill string are constantly conditioning

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Underbalanced Drilling Shortcourse

the hole. With slide drilling it is necessary to make frequent short trips to compensate for the lack of rotation. Rotating the downhole motor can continue at all times during short trips and full trips and helps balance this problem. CT is an excellent backreamer which can help if any swelling problems are encountered. a)

Drilling Operations

Drilling is accomplished with downhole motors, and frequently accompanied by MWD, steering tools, and adjustable orienting devices when needed. No rotation allows for continuous surface readout of all downhole information through wireline. The combination of live data and no connections permits continuous pumping and makes it possible to maintain a fairly constant underbalance. This coupled with 4 phase flow information from a closed return system allows for drilling optimization that has not previously been possible. Most CTUs have monitoring systems that are easily adapted to drilling. The system records wellhead pressure, pump pressure, pump rate, depth, weight, and running speed. Adding inputs from the surface system is usually not difficult. With the addition of return rates and downhole information like BHP, BHCTP, deviation, and direction, the control cab has all information required to monitor underbalance pressures, motor pressure drop, and record all information for post drilling analysis. The work floor for the CTU is often designed to raise and lower. This allows the floor to be adjusted to provide some support for the injector head when it is connected to the wellhead. Hydraulic power tongs are used for making and breaking the pipe b)

Tripping

There are no connections and no tool joints to consider when tripping. The well can be shut in or flowed for the trip and the coil run pipe light without problems. To handle the BHA it is necessary to either have enough lubricator to cover the BHA or as a second choice, bullhead enough fluid to safely handle the BHA rig style. This decision will be based on the length of the required BHA. The BHA can be stripped through the Annular at low pressures. For higher pressures either a lubricator or a snubbing jack/traveling slip system is required.

3.

Limitations

The primary limitations to CT drilling today are depth, circulating rate, availability, and cost. a)

Depth

The primary depth limitations in reentry wells relate to pipe strength and pull capacity, and in new wells, to hole size. CT has operated below 20,000’ in cased hole, and stronger pipe and injector heads are becoming available. CT reentry drilling has been successful at 9000’ TVD drilling 2500’ horizontal sections and at greater depths vertical. Theoretically, a CTU with 2-3/8”, 0.156 wall, Q-800 pipe could drill to 20,000’ with a 10,000# BHA and have a 28% minimum yield safety factor coming off bottom. This renders 28,000# overpull capacity on bottom. The chances of sticking would be very high with such limited overpull. The primary depth limitation in new well drilling is hole size. To drill a new well to 10,000’ may require a surface hole the CT is incapable of drilling. Even in slimhole drilling, the required flowrates in the surface hole may exceed the capacity of CT. The presently accepted new well depth limitations are believed to be 5 - 6,000’. This could potentially be extended by setting surface casing with a small rig or pulling unit and switching to underbalanced CT drilling.

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Most CT is presently limited to 80 ksi yield although 100 ksi yield pipe is available. The 20% increase in pipe yield translates to a 20% increase in depth capability. A 150,000# pull injector head is on the market now. Drilling rigs use 135 ksi drillpipe for a weight/strength ratio that allows deep drilling. The CT pipe strength for deep drilling is not in the near future. b)

Circulating Rates

The most common tubing size used presently for CT drilling is 2”. The workable flowrates are 3 - 4 BPM which are appropriate for motors up to 4-3/4”. In large holes cleaning may become a problem. Coiled tubing is available up to 4-1/2” OD which will allow normal rig circulating rates. This pipe, however, is difficult to handle due to weight and reel size and has a much shorter fatigue life than smaller CT. c)

Equipment and Personnel Availability

The number of units available is growing as the market grows. Availability of equipment can be a problem, but the primary problem now is finding CTU crews that have drilling experience. With the growth in CT drilling, most experienced crews are busy. The CT drilling experience level of the operators representative, CT supervisor, and crew is critical to safe efficient operations. d)

Operating Cost

Operating costs are much more than drilling the well with a standard rig and standard mud. Economics, however, are frequently much better. The many advantages of drilling underbalanced combined with the specific advantages of drilling with a CTU can combine to create very attractive economics on a well that would carry too much risk, such as safety or formation damage, to drill with standard equipment and overbalance methods. In general, the daily cost will increase if CT is used. Some cost can be recovered from faster operations but it is normally other considerations, like safety, environmental risk, and location limitations, that make CT drilling desirable.

4.

Summary

Slimhole coiled tubing underbalanced drilling with a closed surface system combines many years of development into a single system. This combined system was developed from incremental steps that were each a bit better than the previous, and steps that could not be combined previously. With continued improvements, this is a powerful tool to drill undamaged wells in very difficult circumstances. Expandable coiled casing is under development to allow drilling the same hole size for more than one interval. The expansion rate is 120% - 130% which would allow drilling a section, casing it, and drilling the next section the same size. This will help eliminate some depth limitations by not requiring large surface holes. CT underbalanced drilling provided some obvious benefits and some observed benefits that were difficult to understand. After several wells demonstrating less washout and better log quality at similar flowrates, the operator realized that the stabilized flow regime was less destructive to the wellbore than discontinuous flow experienced with jointed pipe. a)

Advantages

CTU underbalanced drilling has some substantial advantages over other methods discussed. •

Safer underbalanced drilling,

•

Lower environmental impact, such as noise, spillage, location size,

•

Ability to use wireline for real time downhole data gathering,

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b)

Underbalanced Drilling Shortcourse

•

Faster drilling in soft formations, as there are no connections,

•

Minimal washout and improved log quality,

•

Fast mobilization and rig - up.

Disadvantages •

The fatigue life of coil decreases with size. Larger sizes of coil have a short cycle life and could cause additional cost and delays while changing pipe. This not a problem on short sections but could be on a new well with large CT.

•

All rotation is by downhole motor for both drilling and fishing. Non-rotating fishing tools are normally used.

•

WOB is limited, although with surface handling equipment, collars can be added.

•

Pulling capacity is limited. Note that new heads with 150K pull and hydraulic assist rams are overcoming this limitation.

•

Day rates are high. Present costing is based on very short jobs. With longer term contracts pricing improves.

c) Design Criteria There are many cases where CT drilling should be examined for potential benefit or as a solution to specific problems. •

Through tubing reentry, like deepening or horizontal kick-out,

•

New shallow slimhole wells,

•

Where space is a major limitation; for instance, offshore,

•

Exploration wells for P&A or monitoring. Note that final borehole will be small,

•

Where safety or environmental issues are a controlling factor,

•

Where formation damage from any overbalance is the overriding concern,

•

Remote or expensive operations.

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IV.

Page 79

SUMMARY OF UNDERBALANCED DRILLING TECHNIQUES

This section is a tabular summary of underbalanced drilling methods. The first table is techniques primarily used for hard, competent , tight formations. The second table is methods used more for softer, more productive formations. The division of gas based and liquid based fluids is not strictly correct, but based on fluid weights. The foam systems are fluid, continuous phase systems but have been included in the “gas based systems” due to densities.

A.

HARD FORMATIONS

Hard competent formations can usually be drilled with a gas based circulating medium. Dry air, nitrogen, natural gas, stable foam, and stiff foam all fall into this category. The common factor is large underbalance pressures and the associated increases in ROP. Frequently these formations will require stimulation so formation damage may not be an issue. Gas based drilling is often used in upper hole sections to reduce drilling time.

B.

SOFT FORMATIONS

Softer formations will more commonly be drilled with a fluid based system, either lightened or naturally below the formation pressure gradient. Wellbore stability and formation damage are typically the driving force behind this style of drilling. Increased penetration rate is normally less important and may actually be slower on average because of the smaller percentage of time rotating on bottom. Gasified liquids and flow drilling fit this category. Mudcap drilling may not actually be “underbalanced” but fits better in this category than the first. Snub and coiled tubing drilling are typically used in high permeability situations where liquid systems are appropriate. Closed system drilling can be used in any type of underbalanced drilling and has been included with liquid based drilling for convenience.

C.

TABLES

The following tables provide a summary of the strong and weak points of each system. The division by hard formation, gas based, and soft formation, liquid based, is for convenience and is not correct in every case. The choice of system will be based of the well information, not an arbitrary designation of the system type.

Summary

Page

80

Underbalanced Drilling Shortcourse

HARD FORMATION METHODS Underbalanced

Strong points

Weak Points

Design Criteria

No Formation Damage

Intolerant of Water Inflow

Hard Rock

Fastest ROP

Danger of Downhole Fire

Lost Circulation

Long Bit Life

Wellbore Instability

Easily Damaged Target

No Shale Swelling

Can’t use MWD

Good Wellbore Strength

Can Drill with Percussive Bits

Can’t Drill H2S

Limited Groundwater

Drilling Method Dry Air

Nitrogen

No Lost Circulation

No High Pressure or H2S

Uncontaminated Cuttings

ROP Sensitive to Pressure

Same As Dry Air

Same as Dry Air

Same as Dry Air

No downhole fires

Expensive

Downhole fire problems Horizontal well

Natural Gas

Mist

Same as Dry Air

Same as Dry Air

Same as Dry Air

No downhole fires

Expensive

Downhole fire problems

Cheaper than nitrogen

Fire danger at surface

Available gas supply

Handles more water flow

Shale problems

Moderate water inflow

Eliminates mud rings

Higher air rates Corrosion

Stable Foam

Stiff Foam

Handles more water flow

Higher additive costs

High water inflow

Improves lifting capacity

Must break foam

Wellbore instability

Less wellbore erosion

Must dispose water

Erosion

More formation support

Corrosion

Cuttings removal

Better hole cleaning

Difficult to break

Large holes

Handles more water

Corrosion

Water influx Contamination of foam

Summary

Underbalanced Drilling Shortcourse

Page 81

SOFT FORMATION TECHNIQUES Drilling Method

Strong points

Weak Points

Design Criteria

Gasified Liquid

BHP control

Slower penetration rates

Wellbore instability

Mechanical wellbore support

Corrosion

High influx

Tolerates influx well

MWD possible

Limited underbalance

No compression equipment

Hole cleaning

Higher pressures

MWD works

Oil/gas handling

Lost circulation

Flow

Wellbore instability

Less corrosion Good BHP control Mudcap

No flow to surface

No returns

No other choice

No cuttings

High H2S Lost circulation

Snub

Coiled Tubing

Higher pressures

Expensive

High Pressures

Can maintain Underbalance

Slow

Severe formation damage

Safety

Rotation

Through tubing

High pressures

Weight on bit

Shallow slimhole

Environmental

Pull capacity

Size restrictions

Wireline data

Expensive

Safety/environmental

Faster

Formation Damage

Little washout

Remote expensive Ops

Fast mob/RU Closed System

No pits

Costs

High H2S

Safe

Danger from oxygen

High Productivity

Accurate measurements

High pressures

Environmental

Limited work area

Small footprint

Need for information

Summary

Page

V.

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Underbalanced Drilling Shortcourse

COMPLETIONS

In many cases, after wells are drilled underbalanced (and presumably undamaged) they are killed in preparation for completion. It is possible to create significant formation damage and/or lose large amounts of expensive completion fluids at this point. If formation damage and cost are the driving forces behind underbalanced drilling initially, formation damage and cost should be the driving force behind completing the well. Completing in this case will be considered to be all operations conducted after the well is drilled. Consideration must be given of all options to maintain the underbalanced conditions throughout the completion. This extends through logging, casing, and completing the well.

A.

PRODUCTIVE ZONE

Casing the productive zone can be approached several ways. No casing, called open hole completion, is an option, or cemented or non-cemented liners can be used.

1.

Open Hole

An open hole completion is the easiest method for eliminating completion fluid damage. This method is only applicable where the formation has the competence to not require casing. The open hole completion is the cheapest and runs the smallest risk of becoming overbalanced during completion.

2.

Slotted Liner

Formations that need the support of casing can be completed with a slotted liner. This is applied in many horizontal wells and includes pre-perforated liners and screens. The problem with this type of “liner” is that there is no way to strip it into the well with the well flowing. A pre-drilled coiled tubing liner with plugs in the holes is available that can be run underbalanced and jetted to bottom if necessary. The plugs can then be removed with HCl or mechanically removed. This liner is available from 2” to 3-1/2”. A non-perforated liner can be run in and then perforated, but in long sections the cost of perforating is high. Slotted liners are typically run with a wash string through the liner to allow jetting if problems are encountered while running to bottom. A system has been devised to allow running this equipment without overbalancing the well. Downhole Lubricator Method: An inflatable bridge plug is set in the casing deep enough to allow the entire liner inside the well above the plug, and allow enough pipe weight to strip against any surface pressures present. The bridge plug is set and the well bled at surface or enough fluid spotted above it to balance or overbalance the pressure across the plug. The fluid provides a second level of protection from the formation and reduces the chances that the bridge plug could fail. The formation is isolated and will come to equilibrium below the plug. Any surface pressure is bled and the liner is run normally with a J-latch shoe that can pull the bridge plug. Once the liner is in the well and crossed back to drill pipe it is possible to strip. The bridge plug is latched and the fluid circulated from the well. The bridge plug is then unseated and the liner run to bottom and hung off normally with the well underbalanced. The bridge plug is left in the hole or retrieved through the liner depending on the type used.

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Underbalanced Drilling Shortcourse

3.

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Cemented Liner

A normal liner can be stripped or snubbed into the well without difficulty. The problem arises when it is time to cement. Foamed cements are available, staged cement jobs are common, and casing packers can be run. But at some time the well will be overbalanced or the cement will probably not be good. Cementing with the well flowing is not an option and no other method ensures that the well remains underbalanced. Cementing the liner should be approached by minimizing the overbalance and damage while maximizing isolation. Some horizontal liners are run with multiple open hole packers and not cemented. This method can maintain underbalanced conditions and provide some isolation and production options. Sliding sleeves are run to provide access to each open hole interval. This method is a compromise between isolation and damage and can be applied successfully in the right circumstances.

B.

PERFORATING

1.

Underbalanced Perforating

Perforating underbalanced has been an accepted method industry-wide for many years. In the past it has been common to kill the well after perforating (TCP) or to perforate after completion with smaller, shorter guns to allow for enough lubricator to cover the guns. The benefits of large tubing conveyed guns and underbalanced perforating have been well documented. A formula has been developed for calculating the required amount of underbalance. The formula uses porosity, perforation diameter, and permeability to calculate underbalance differential. This tool assists in determining how much underbalance to apply. The formulas predict higher underbalanced pressures than are commonly accepted but do provide a starting point rather than a fixed pressure differential for all underbalanced perforating. An in depth treatment of the formulas can be found in SPE 30081 listed in the bibliography. ∆P = 1480φD0.3/k1/2 , ∆P = 630φD0.3/k1/3 ,

for k > 100 md. (hint: The porosity is 25, not 0.25) for k < 100 md.

Where φ, porosity in %, D, perforation diameter in inches, and k, permeability in md, and ∆P, underbalance differential in psi. To utilize large TCP guns before the completion is run and maintain the underbalance when retrieving the guns requires a downhole shut-in of some sort. It is conceivable to run a large downhole swab in the casing to allow running a slotted liner or large TCP guns. No documentation has been found of field trials of this method, but it is the same technology as the DSV and should not be difficult to achieve. The problems to be addressed are finding a large enough ball valve, and dealing with the control line at surface. Tubing retrievable ball valves are common up to 7” and adapting the wellhead for the control line should not be difficult

C.

COMPLETION

Once the well has been prepared for completion, consideration should be given to future situations that will require the well killing. Some additional equipment such as a downhole swab valve may be included in the completion to maintain underbalanced conditions during operations. Once the completion is designed, placement of the completion into a live well must be considered if the production casing is not cemented or if TCP guns are to be run before the completion. The completion

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Underbalanced Drilling Shortcourse

can be designed to be snubbed into the well, be run on coiled tubing, or be run normally with the aid of a bridge plug.

1.

Downhole Swab Valve

When using long tubing conveyed perforating guns, it is easy to perforate underbalanced but difficult to remove the fired guns without killing the well. When perforating through the completion, an additional downhole ball valve, that is designed normally open, can be placed above the SSSV to provide a pressure barrier in the tubing. This will allow introduction and removal of long assemblies. When the TCP guns reach surface, the pressure can be bled from the downhole swab valve control line, closing the DSV, and the well bled for removal of the guns. This will also allow for future long assemblies to be run with the well live for reperforating or deepening with coiled tubing.

2.

Snubbing

The completion can be designed to be snubbed ram to ram past the packer and then stripped to bottom. Careful consideration to the outside profile of the completion and to the placement of nipples in the string will allow an uneventful completion. The additional expense of the snubbing unit can be offset by releasing the rig and by reducing formation damage.

3.

Coiled Tubing

Coiled tubing completions with profiles, gas lift mandrels, and SSSV nipples are preassembled at the factory. They can arrive on location complete, and with the addition of a packer/tailpipe assembly, be ready to run in the hole. These completions are becoming more common and provide the additional benefit of fast placement and rigless workovers in the future. The additional cost can be recovered by releasing the rig, reduced formation damage, time, and faster future workovers. In offshore or remote locations, the savings in time, lost production, and cost of future workovers make this system very attractive.

4.

Standard

With the utilization of a downhole lubricator (bridge plug), the rig can perform a standard completion while isolated from the formation. The bridge plug can be retrieved (if inflatable) or pulled with a workstring or coiled tubing and dropped to bottom. The danger of being blown uphole will preclude unseating the bridge plug with wireline in most cases.

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VI.

SAFETY, ENVIRONMENTAL, AND REGULATORY ISSUES

A.

SAFETY

The general safety of underbalanced drilling appears to be the same as overbalanced drilling. In some cases the designed ability to handle hydrocarbons and H2S may make underbalanced drilling operations safer than standard practices. Utilization of an RBOP and a carefully designed surface system allow safe drilling operations while flowing the well.

B.

ENVIRONMENTAL

The surface handling of hydrocarbons, formation water, and H2S present potential environmental hazards that must be addressed in an underbalanced drilling operation. With proper equipment, zero discharge operations are carried out every day. The environmental advantages of underbalanced drilling include, •

Less surface damage due to a smaller footprint,

•

More control of well fluids due to planning and equipment.

As in all operations, the environment must be protected. The equipment utilized in underbalanced drilling creates a natural situation to provide additional insurance against environmental damage.

C.

REGULATORY

In the United States there are no regulations specific to underbalanced drilling. In Canada and the U.K., there are general and specific regulations for UB drilling. The operator is required to adopt safe and prudent practices in situations that are not specifically covered in the regulations. API RP 53 draft section 13 covers underbalanced drilling and EUB (Canada) Interim Directive ID 943, included in the bibliography, contains regulations controlling UB drilling. The regulatory body with jurisdiction over the well should be contacted to verify that no new regulations exist and to get agreement that the practices adopted are “safe and prudent." A properly designed well plan will be safe and prudent as long as the equipment dictated by the conditions is provided and properly maintained. Thousands of underbalanced wells have been drilled in North America and the practices are well established

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VII. CANDIDATE SELECTION Not every well is a good candidate for underbalanced drilling. In some cases there are distinct disadvantages. It is important to properly assess the prospect to determine if there is merit for underbalanced drilling. Two main criteria in deciding whether or not to implement underbalanced drilling technology are technical or economic advantage, and weighing the advantages versus the risk. If the assessment indicates that the well is a good candidate, the process continues through economic analysis and technical merit.

A.

EXAMINING THE CANDIDATE

The gathering and analysis of data provides a quick look at the general applicability of underbalanced drilling to a candidate. The screening process starts with data gathering and analysis, involving economics and technical merit on a macro scale to decide whether to proceed with UB drilling. If the data indicates a good prospect, the process proceeds.

1.

Screening Process

Screening wells for UBD is challenging and requires extensive effort. Therefore, consider every negative aspect which would preclude the candidate from underbalance drilling. Early detection will prevent expending valuable efforts on poor candidates and misapplications of UBD. There are three options for underbalanced drilling a well:

2.

•

Upper hole only,

•

Production hole only,

•

Entire well.

Acquisition of Data

Initially a limited amount of data is desirable to readily determine if the well fits enough underbalanced drilling criteria to warrant further analysis. a)

Quick Look Data

Any readily available data from drilling in the area around the prospect will assist the engineer in performing a quick look to see if UB drilling is appropriate for the well. This should provide: •

A pore pressure plot,

•

ROP curves,

•

General production rates for specific formations,

•

Present pressures for producing formations from close offsets,

•

FIT information,

•

Clues about water sensitive shales,

•

Location and severity of lost circulation zones,

•

Presence of H2S.

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Offsets Any underbalanced drilling in the area, successful or not, will provide much information needed for this step. If a similar well was unsuccessfully attempted UB, it may have the key information on how to successfully drill UB in the same area. If successfully drilled UB, it will provide a starting point for designing a better program. Company drilled offsets, either UB or OB, will give more comprehensive information but are not the only source for important information. Basin Information Any wells drilled in the general area may provide clues to the geological stability and pressure profiles in the area and help to develop a reasonable picture of the pressure and wellbore stability necessary for a quick analysis of a prospect.

3.

Analysis of Data/Quick Look Criteria

A quick look technique should be applied to eliminate unsuitable candidates before much time and money is invested in underbalanced drilling designs and engineering. Some items unquestionably eliminate UB drilling. First the data should be arranged by hole section. Each part of the analysis should be done on every hole section. A well that is not a UB candidate may have one section with excellent economic benefit for UB drilling. An economic UB drilling candidate may have one section that is not economic to drill UB. The best overall plan requires that the well be viewed as several separate jobs, each having a unique solution. Once data has been acquired there are some key items to check in the quick look process. a)

Global Items

Determine if concerns about safety, environmental issues, or drilling problems might override economics as a deciding factor. High Pressure If the potential surface pressures are above the safe working limits of a rotating BOP, the well may require a snubbing unit or a coiled tubing unit or may not be a candidate for UB drilling. Production If the well has high production rate potential, the surface equipment must be capable of safely handling the flow rate. H2S If H2S is present, the well may require a closed system or returns to surface may not be acceptable. Reserve Pit/Location If the reserve pit or location size are critical issues, the direct cost of the well may not be the driving force behind the decision on how to drill.

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88

Lost Circulation If lost circulation is a major concern, UB drilling may eliminate this problem.

b)

Technical Aspects

Wellbore Stability The first decision to start quantifying the economics of drilling underbalanced is to determine if the pressure restraints on the wellbore dictate a gas or liquid system, or fully excludes UBD. Once the pressure limits have been determined, the system type can be determined using the charts below, Figure 7-1. Once the system is chosen, estimates can be prepared on daily costs since it further defines what equipment will be necessary.

PRESSURE RANGES Liquid vs. Gas Systems 4500

Liquid Based Systems P R E S S U R E

P R E S S U R E

Liquid Range

Foam Range w/ Backpressure

2500

i n

Gas Based Systems

900

Foam Range

450

i n

Gasified Liquid Range

P S I

P S I

Mist Range

Air / Mist / Foam Drilling 0

Dry Air Range

0 0

5,000

10,000

DEPTH in FEET

0

5,000

DEPTH in FEET

Figure 7-1: Pressure Ranges of Various Underbalanced Drilling Systems Defining the Pressure Limits To define the pressure limits, a sonic log or underbalanced drilling information from an offset is needed. The upper limit, by definition, is the pore pressure plot. The lower limit must maintain wellbore stability. It is possible to calculate pressure differentials from the sonic log. This requires both the compressional wave velocity and the shear wave velocity which may not be available. See GRI UB Drilling Manual for more information. As a rule of thumb, a well with sonic travel times consistently below 70ms is probably a good air drilling candidate. If offset information exists, the lowest pressures without wellbore problems can be used with the above charts to determine which systems can be applied.

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At this point in the design, the decision to use a gas or liquid based system is enough to continue. Later in the design, other information will be added to determine precisely which system and what additives will be required. Increased ROP •

Will the well drill faster underbalanced?

The increased ROP associated with underbalanced drilling must be discussed as two different subjects. The division is permeability. In permeable rock the mechanics of increased penetration are different from the increased ROP in impermeable rock. Permeable Rock The increased penetration rate due to drilling underbalanced is related to permeability and differential pressure. The hold down forces on a cutting, combined with the time required for the pressure at the cutting to equalize appears to be one of the driving forces of ROP in a permeable rock. In a tight formation the time is significant for the differential pressure holding the cutting in place to equalize and release the cutting. The differential is critical to ROP. With high permeability the time is shorter. The most gains in ROP experienced in a permeable formation will be in an underpressured zone where the typical overbalance is high. The greatest gains in ROP seen in a permeable zone are in the overbalanced to balanced range. This will increase typically ROP by 30% to 300% depending on the initial overbalance. In cases where the formation is underpressured, the overbalance is very high and the gain can be 1000%. From balanced to underbalanced is usually a small gain, 10% - 20%, compared to OB to balanced. Keep in mind that in many cases reaching the balance point requires some form of “underbalanced drilling." Impermeable Rock. In impermeable rock, the mechanics of increased ROP appear to be absolute BHP. The inability of the rock to equalize allows all of the potential energy stored in the formation, that is pressure, to appear as drilling energy. The lower the borehole pressure, the faster the ROP. This explains, in part, the increased bit life experienced in UB drilling. The bit does less work so it drills more feet before it is worn out. Summary Rules of thumb are convenient for estimating ROP for a macroeconomic look at the well. A good, safe method of projecting ROP when better information does not exist is to either double the ROP below 50’/hr or add 50% above 50’/hr. There is no basis for this rule. Through reading the literature and case histories the increase is 0% to 1000% but 100% increase appears to be a safe low end for most cases where the original ROP is not extremely high.

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Reduced Formation Damage Is formation damage a concern, and if so, will UB drilling reduce the damage? The recognized mechanisms of formation damage include: •

Formation of scales, sludges, or emulsions,

•

Interaction of water and clays in the formation,

•

Invasion of drilling mud solids into the formation,

•

Invasion of fluid causing phase trapping or fluid blocking,

•

Adsorption of chemicals causing reductions in permeability or relative permeability,

•

Migration of fines in the reservoir, typical of high pressure gradients,

•

Deposits caused by bacterial contamination.

These are normally associated with overbalanced drilling. Underbalanced drilling does not eliminate all of the above. The damage associated with underbalanced drilling is

c)

•

Temporary overbalance,

•

Gravity induced invasion,

•

Wellbore glazing,

•

Post - drilling damage,

•

Mechanical degradation,

•

Spontaneous imbibition.

Macro Economics

Determine if there is a benefit that may translate to dollars to economically justify the well. The big picture on economics involves three different comparisons. •

The daily cost for the projected number of days for each method plus the costs for construction, mobilization, disposal, and reclamation, gives a good first look at comparative direct costs.

•

The benefit of increased production and additional produceable reserves, or the savings from not stimulating the well provide the second bit of information.

•

The risk cost for lost circulation, environmental damage, safety concerns, lost BHA, sidetracks, etc. can be factored in to complete the economic overview.

Some items are difficult to quantify. On the other hand, simple economics can be used. For example, if 25% of the wells in a field have required a $500,000 sidetrack, the risk cost is $125,000. If underbalanced drilling can cut the number of sidetracks in half, a reduced risk cost of $62,500 can be assigned to the well. When the risk cost is added to the well cost, a more realistic picture is presented.

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Time Requirements Will the overall drilling time be shorter? The following are two simple examples to show how ROP can be used as a quick look for economics. Case: A well has a 3000’ section drilled with mud with 100 connections at 5 minutes per connection. This equates to 8.3 hours for connection time. It takes 3 hours to trip in to 6000’ and 4.5 hours to trip out from 9,000’. The total trip time with mud is 7.5 hours. Example 1: Hard section: Air vs. Mud : Double penetration rate (5’ mud, 10’ air) plus 50% longer on connections and trips: Fluid

Rot. Time

Conn. Time

Trip Time

Total Time

Mud

600 hr.

8.3 hr.

7.5 hr.

615.8 hr.

Air

300 hr.

12.5 hr. 11.2 hr. 323.7 hr.

Example 2: Softer more permeable section: Gasified Liquid vs. Mud : Add 50% to penetration rate (150’ gas/liquid, 100’ mud) plus 100% longer on connections and trips: Fluid

Rot. Time

Conn. Time

Trip Time

Total Time

Mud

30 hr

8.3 hr

7.5 hr.

45.8 hr.

Gas/Liq20 hr

16.6 hr.

15 hr.

51.6 hr.

It becomes obvious that ROP is only a major concern if significant time is spent rotating.

Increased Production •

Decide if the well will produce more if it is drilled underbalanced.

There may be a definable increase in production with two effects: the NPV of the production increases, and the economic limit of the production may be extended. These two benefits, increased early production and increased reserves, may combine to justify additional expenditure for underbalanced drilling. Using standard calculations for PI in a vertical well, the comparison for a skin of 5 and 0 is shown in the following example. Example: Offset wells have been shown to have a drilling induced skin of 5. The PI calculation is as follows: k = 100 md, h = 50’, µ = 2 cp, Bo = 1, Re = 2106’ ( 320 Ac), Rw = 0.354’ (8.5”),

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Underbalanced Drilling Shortcourse

0.00708 k h

. =

µBo[Ln Re/Rw - 0.5 +s]

35.4

.

16.38 + 2s

With a skin of 5, drilled overbalanced, the production rate with 500 psi drawdown will be 670 BOPD. With the skin reduced to 0 by drilling underbalanced the rate will be 1080 BOPD. The increase of 410 BOPD at a net of $15/Bbl is an additional $6,150 per day. The first month nets an additional $184,500. This is enough to cover the extra drilling expense. In the same example: The initial production is 670 BOPD and 1080 BOPD respectively. Using decline rates of 5% and 8%, which is the same ratio as the production ratio, and an economic limit of 50 BOPD then: The damaged well produces 380,000 Bbl oil in 52 months and is then shut in. The undamaged well produces 394,000 Bbl oil in 38 months. The increase in net present value (NPV) is a combination of faster production and increased production. The calculations of net present value for these two examples is based on a 10% investment opportunity rate. The following chart is NPV as a fraction based on 10% discount rate. NPV = ∑(1+Dr)-t

N e t P re s e n t V a lu e 1 0 .8

N P V

0 .6 0 .4 0 .2 0 0

1

2

3

4

5

Y e a rs Figure 7-2: Net Present Value as a Fraction The increased production is based on a lower abandonment pressure before the well reaches its economic production limit. The following figure is an example of the difference in abandonment pressures.

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Economic Life of Well due to Reservoir Pressure

Min Res Pressure for Economic Production P r e s s u r e

Min Res Pressure for Economic Production

P r e s s u r e DP from Skin > 0

Skin = 0

Distance from Wellbore

Distance from Wellbore

Figure 7-3: Abandonment Pressure as a Function of Skin When these increases are calculated as NPV for the well the results are as follows: YEAR

NET PRICE

PROD S=5

VALUE

PROD S=0

VALUE

1

$15.00

187,697

$2,815,455

260,104

$3,901,560

2

$13.63

101,321

$1,381,005

95,556

$1,302,435

3

$12.39

54,717

$677,943

35,075

$434,579

4

$11.26

29,646

$333,813

3,141

$35,367

4-1/2

$10.80

6,435

$69,508

0

0

379,816

$5,277,724

393,877

$5,673,941

TOTAL

The increased oil recovery is 3.6%, and the increase in NPV is 7.5% or $396,217. Other Considerations The special circumstances of a particular well may justify or require that the well be drilled underbalanced. In environmentally sensitive regions or limited footprint areas, it may be necessary to drill with coiled tubing into a closed system. If the well is going to carry the economic load for all that equipment for other reasons, it is likely that UB drilling will improve the economics. Even if the well was not as economic as an underbalanced drilling candidate a reevaluation with the expensive equipment included both for OB drilling and UB drilling may make UB drilling more attractive.

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Underbalanced Drilling Shortcourse

Conclusions

Now there is enough information to decide whether continued effort examining the candidate is justified. a)

Can Underbalanced Drilling be Used

Will the pressure limitations allow underbalanced drilling? Is there a benefit that might justify any additional costs? Are there other problems with pressure, flowrate, H2S, or anything else that would preclude drilling underbalanced? b)

Gas or Liquid System

Choose the system, whether gas based or liquid based, for drilling the well. c)

Hole Sections

Determine which hole sections are candidates for underbalanced drilling. Does each hole section require the same circulating system? d)

Summary

If the candidate appears to be viable at this point, it is necessary to make a more detailed examination of the well to prepare for writing an AFE and programming the well.

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VIII. WELL PLANNING Well planning involves a series of steps and ends with the information required to write an AFE and a drilling program. This process starts with detailed data and progresses through picking the system(s), designing the fluid, calculating the required materials, calculating the disposal volumes, and specifying the equipment.

A.

CHOOSING THE METHOD

Choosing the method will require more data than the prior decisions. All of the data in the following lists are not required to design and drill the well, but any data may help to avoid problems and enter the learning curve at a better location.

1.

Detailed Data Gathering and Review

Data gathering is broken up into two categories: upper hole section and production hole section. If the decision has been made to only drill the upper sections underbalanced the second set of data is unnecessary. Fill in all available information. Information that doesn’t exist can be estimated or ignored. a)

Detailed Data Gathering

For Upper Hole Sections Hole Section Properties

•

Pore pressure plot for the interval from offset drilling records,

•

Pressure variations, either charged or depleted zones from offset drilling records,

•

Presence of lost circulation zones from offset drilling records,

•

Location of water zones, from offset logs,

•

Productivity of water zones, may be estimated from open hole logs,

•

Time vs. Depth Plot, from offset drilling records.

Rock Properties

•

Formation strengths, use Gradient Plot of Minimum Allowable Pressure,

•

Water sensitive shale sections from offset drilling records, tight hole or reaming,

•

Erosion potentials, from offset caliper logs.

Influx Fluid/Drilling Fluid Compatibility

Information on fluids other than a productive interval can be difficult to obtain. Offset production records from upper zones, log information, and possibly information from a waterflood source well could provide this information. The geology department may have some information on upper productive zones they have gathered.

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Underbalanced Drilling Shortcourse

96

•

Emulsion potential

•

Scale potential

•

Corrosion potential

•

Contamination of circulating fluid by influx

Rock/Drilling Fluid Compatibility

The source for rock information is the geology department. Mud log or geophysical description of cuttings, with the help of a geologist, can provide much of the information about the rocks. •

Potential reaction with clays and shales

•

Formation dissolution

•

Reactivity and transport of cuttings

For Production Hole Section The reservoir engineering department should be able to provide most of the information below. Some of the rock information will come from the geology department. Reservoir Properties

•

Current target reservoir pressure

•

Presence and pressure of multiple zones

•

Pressure variation within the reservoir(s)

•

Location of oil, gas, and water contacts

•

Presence of sealing/nonsealing faults

Rock Properties

•

Reservoir lithology

•

Vertical and horizontal permeability

•

Porosity

•

Pore size and pore throat distribution

•

Presence of faults, fractures, vugs, etc.

•

Formation strengths

•

Initial saturations

•

Capillary pressure characteristics

•

Wetability

•

Relative permeabilities

•

Glazing potential

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97

Reservoir Fluid Properties

·

Compositions

·

Asphaltine/paraffin contents

·

Cloud and pour points

·

Viscosities and densities, both downhole and surface

·

Bubble point and PVT properties

·

Dew point and CVD properties of rich gases

·

Presence of H2S or other hazardous components

Reservoir Fluid/Drilling Fluid Compatibility

·

Emulsion potential

·

Hydrate potential

·

Scale potential

·

Precipitation or asphalt deposition potential

·

Gas entrainment characteristics

·

Explosion potential

·

Corrosion potential

·

Degradation of drilling fluid by formation fluids

Reservoir/Drilling Fluid Compatibility

b)

·

Potential reaction with clays

·

Potential reaction with hydratable shales

·

Formation dissolution

·

Countercurrent imbibition potential

·

Reactivity and transport of cuttings

Detailed Data Analysis

The data needs to be turned into plots and organized in a fashion that is useable. Final pressure envelope plots and lists of potential sensitive areas should be composed. An Overbalanced Drilling Time vs. Depth Chart needed for typical AFE approval should be completed for economic comparisons.

2.

Underbalance Design

a)

Which Systems Apply

Now that the data is gathered in one location, determine which system is applicable. The company providing the fluid chemicals has a trained expert who can go through the data with you and help decide which systems are compatible with the pressure profile you have developed and the rock and fluids in the well.

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A further look at the geology with the geologist in charge of the prospect may be warranted after the system is chosen. He may see potential problems that can be designed out of the program. b)

Pick the System

It should now be apparent which system will work best for drilling the well. Keep all information collected in case the decision path changes. C)

Build a Time vs. Depth Plot for the Method.

Using offset information or penetration rate estimates, connection and trip time estimates, and the OB drilling time plot, build a time plot for UB drilling the well. This is critical in all of the economic justifications and should be very carefully constructed to be as accurate as possible.

3.

Fluids Design

a)

Fluid Weight

The general system has been chosen partially to provide optimum fluid density for the well. Add the projected fluid density to the pressure range plot to show how close to any limit the system is. This will help plan contingencies for operating outside the allowable pressure range. In addition, consider what unexpected situations may occur and the effect it would have on the chosen system. b)

Corrosion Program

Any system that includes water and air will require a corrosion program. Most other programs will also but they are much simpler and not as critical. Call the fluid company and have them design a corrosion program and explain it. c)

Circulating Rates

The range of circulating rates based on depth, cleaning, and influx must be calculated. This includes gas and liquid rates separately. Computer programs, like Mudlite, Circa, or other vender products, are available and necessary to complete this step. d)

Fluid Recipe

With this information, the service company can design a complete system. Note that this should be provided for each hole section. e)

Material Requirements

Using the information from the time, circulating rates, and recipe, build a complete materials list for the well. Have the service company do the same and have them recommend additional materials needed on location and what is available from town. Compare the two lists and compile a final material list.

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Disposal Volumes

Total disposal volumes are required to estimate disposal costs. If a disposal well is available or annular injection is an option, there may be little or no cost. Total volumes are still required to calculate safe storage, trucking requirements, etc. a)

From Fluid System

Since no fluids are lost in UBD, then the material list plus the recipe gives the total liquid required for the well. b)

From Well Influx

Determining well influx is problematic. Hopefully there is enough information about the permeable intervals in the data lists to estimate pressures and rates to be expected from these zones. The geologist's assistance is helpful. Make the best possible estimate with the available information. From the productive interval there should be enough information to make a reasonable estimate. Adding the fluid from the system and the well influx provides estimated disposal volumes. If the numbers are large from the fluid system, investigate recycling to reduce the volumes. If the influx volumes are high, check into annular injection. If the influx volumes are high from the intermediate section of the well, consider using the pit water as a lead to clean the path for your intermediate casing cement job.

B.

EQUIPMENT SPECIFICATION

Knowing what volume, rate, and system will be pumped help determine equipment specifications. The companies providing the equipment can be of great assistance in ensuring that the system is complete, and can give prices, staff requirements, and fuel usage for the equipment. All this will go into the AFE when the planning is done.

C.

COST ESTIMATION

All cost estimates should be broken out by whether they are general or specific to drilling underbalanced. It will be necessary to write an AFE for OB and for UB and compiling costs with that in mind will make the comparison much easier.

1.

Elements

a)

Tangible Costs

Unless there is parasitic injection, or a casing string is eliminated or added, this will be the same for UB as OB.

Well Planning

Page b)

100

Underbalanced Drilling Shortcourse

Construction

After location and pit requirements are set call a location contractor. Have them bid the standard location plus the UB drilling location if there are differences. c)

Mobilization

Include rig, pump system, returns system. d)

Daily Costs

Determine daily costs. Include rig, all rentals, extra personnel, monitoring equipment RBOP, etc. Any charges that will continue throughout the well should be included. Separate the costs into UB drilling costs and general well costs. e)

Pumping System

Any additional costs above mobilization and daily rental cost such as estimated repair costs. f)

Additional BOP

Any one-time charges on the RBOP above daily rental like repairs or reconditioning at the end of the well. g)

Return System

Additional costs on the return system not covered by the daily rental similar to the BOP. h)

Additional Costs

Include any costs that are time specific like directional costs or additional equipment required while drilling production hole. Include bit costs for UB and OB programs. I)

Fluids

Include all material costs from material lists. Some estimate will be required for a standard mud system for comparisons. j)

Demobilization

k)

Disposal

l)

Reclamation

2.

Thumbnail Costs

Some costs specific to underbalanced drilling are included in the following tables. These cost are for estimation purposes only and will vary by area, time, utilization, and vendor.

Well Planning

Underbalanced Drilling Shortcourse

Item

Page 101

Estimated Cost

LOCATION EQUIPMENT Compressor System

Air/Mist

$1450/day plus $32/hr/fuel

Compressor System

Foam

$1125/day plus $22/hr/fuel

Compressor System

Gasified Liquid

$1050/day plus $16/hr/fuel

Cryogenic Nitrogen

N2/Mist/Foam/GL

$1.95/100 ft3 + $2615/day/pump + $1500/day/trk

Membrane Nitrogen

N2/Mist/Foam/GL

$3000/day + $1700/day/diesel

Natural Gas Supply

Gas/Mist/GL

$2.00/MCF

Booster Valve Manifold - Filter

Gas/Mist/GL

$350/day + $16/hr/fuel

Gas/Mist/GL

$65/day

Skimmer Tank System

GL/FD

$1350/day

Super Gas Buster

GL/FD

$210/day

Blooey Line Air/N2/Gas/Mist/Foam

$75/day

Gas Sniffer

Air/N2/Mist/GL

$20/day

Pilot Light

Air/N2/Gas/Mist/GL

$20/day

Closed System Separator Flow Drilling

$3910/day

Fluid Storage

Flow Drilling

$80/day

N2 Unit Standby

Flow Drilling

$765/day

Fluid Pump

GL/FD

$2750/day

Choke Manifold System

GL/FD

$250/day

DOWNHOLE EQUIPMENT Fire Float - Fire Stop

Air

$345/10 day min + $26/day/each

Drill String Floats

A/N2/G/M/F/GL

$500/each

Rotating Control Head

A/N2/G/M/F/GL

$110/day + $515/elements/each

Rotating BOP

FD/MD

$1000/day + $1200/elements/each

Well Planning

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Underbalanced Drilling Shortcourse

102

Coiled Tubing Unit 1 3/4” GL/FD

$18500/day

Snubbing Unit

$7075/day

Snub Drilling

Air Insert Bits Air/N2/Gas/Mist/Foam

6 1/4” $3770 - 7 7/8” $4175 - 8 3/4” $4695

Air Hammer Insert Bits

Air/N2/Gas/Mist

6 1/4” $3685 - 7 7/8” $5621 - 8 3/4” $6667

Air Hammer

Air/N2/Gas/Mist

$72/hr

MM - MWD - GR

Flow Drilling

$6500/day

MM - MWD - GR

C.T.GL/FD

$8850/day

Mud Motor

A/N2/G/M/F/GL/FD

$165/hr + $150/day/monel & kit box

Chemicals Liquid & Solid Additives

Mist Drilling

$2500/day

Liquid & Solid Additives

Stable Foam

$4000/day

Liquid & Solids Additives Stiff Foam

$3500/day

Corrosion Inhibitor

$300/day

Mist/Foam/GL

D.

SUMMARY

1.

Underbalance Method

The underbalance method has been decided.

2.

Surface System

The surface system is designed.

3.

Material Requirements

Material lists have been made.

4.

Disposal Requirements

The disposal costs have been determined.

5.

Cost Estimates

The cost estimates have been compiled and totaled.

Well Planning

Underbalanced Drilling Shortcourse

6.

Page 103

Final Economics

If formation damage is an issue, request a production estimate and a recoverable reserves comparison from the reservoir engineering dept. This should be translated to a net present value for the well with and without damage. See GRI Manual for an in-depth look at present worth calculations. List any drilling problem risk costs for underbalanced vs. overbalanced drilling. This should include any lost circulation costs, sidetrack costs etc. that can be attributed to the well. The AFE and program can now be written. When the two AFEs are finished, do a final comparison including costs, production and reserves impact, and risk. This should be a dollar figure for overbalanced drilling vs. underbalanced drilling.

Well Planning

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Underbalanced Drilling Shortcourse

104

IX.

EXAMPLE UBD CANDIDATE

A.

CANDIDATE SELECTION

The UBD candidate for this exercise was chosen as a fairly typical multiple gas zone, fractured reservoir. The offset comparison well, the Typical #1, is a 6000’ vertical well drilled on 160 acre spacing. The target reservoir is a gas bearing sandstone with 30 milidarcy permeability and 40’ of net pay in two intervals. The intervals are 5200’- 5220; and 5800’- 5820’. It is common to lose partial returns in the pay section area when drilled overbalanced due to the natural fracturing. The initial production rate from the two zones is approximately 278 mcfd and the skin factor has been determined to be +10. Due to the proximity of water, fracture stimulating the zone is not feasible. The purpose of the exercise is to evaluate the economic feasibility of drilling the offset well underbalanced. The only change in reservoir parameters as a result of the underbalanced drilling operations will be the reduction of the skin to zero.

B.

ANALYSIS OF THE CANDIDATE

1.

Offset Data Gathering and Analysis

a)

Offset Data Gathering

(1)

Upper Hole Section (Surface Shoe to 5150’)

(a)

Hole Section Properties •

Pore Pressure Plot for the interval

•

Pressure Variations

•

Presence of Lost Circulation Zones

No Lost Circulation Zones

•

Location of Water Zones

Water Zones from 2200’ to 2420’

•

Productivity of Water Zones

Normal No Charged/ Depleted Zones

High Productivity Brackish Water Zones

•

(b)

(c)

Time vs. Depth Plot

8 Days to Mud Drill Section (7 7/8” hole)

Rock Properties •

Formation Strengths

•

Water Sensitive Shales Sections

No Water Sensitive Shale Zones

•

Erosion Potentials

High Erosion Potential of Water Zones

Low Strength Water Zones (Minimum Allowable Gradient 0.43 psi/Ft)

Influx Fluid/Drilling Fluid Compatibility •

Emulsion Potential

Low

•

Scale Potential

Low

•

Corrosion Potential

High

Example UBD Candidate

Underbalanced Drilling Shortcourse •

(d)

Page 105

Contamination of Circ. Fluid by Influx High

Rock/Drilling Fluid Compatibility •

Potential Reaction with Clays and Shales

Low

•

Formation Dissolution

Low

•

Reactivity and Transport of Cuttings

Low

(2)

Production Hole Section (5150’ to 6000’ TD)

(a)

Reservoir Properties

(b)

(c)

(d)

•

Current Target Reservoir Pressure

( 0.338 psi/ft ) (BHT 123 deg F)

•

Presence and Pressure of Multiple Zones

5200’-5220’ & 5800’-5820’

•

Pressure Variation Within the Reservoirs

None

•

Location of Oil, Gas, and Water Contacts

Gas Column Only

•

Presence of Sealing/Nonsealing Faults None

Rock Properties •

Reservoir Lithology

•

Vertical and Horizontal Permeability

•

Porosity

•

Pore Size and Pore Throat Distribution N/A

•

Presence of Faults, Fractures, Vugs etc.

•

Formation Strengths

•

Initial Saturation

Sw