Basic Completion Categories

There is a significant diversity in the type of completions being used around the

world. However, in general they are variations on a few basic designs. The most

common criteria for classifying completions include

The Interface between the Wellbore and Reservoir

• openhole completions • liner completions • perforated completions

The Production Method

• artificial lift • flowing

The Number of Tubing Strings

• tubingless • single string • multiple strings

The Surface Location

• onshore • offshore (platform) • offshore (subsea)

The Stage of Completion

• initial completion • recompletion • workover

Single-zone completions include downhole commingling of production from several intervals and may be designed to allow sequential development of successive reservoirs. Multizone completions include not only the separation of various zones but also segregation of individual sand units within a thick pay section for reservoir control purposes.

Beyond these major classifications, the completion complexity is largely a function of

the problems encountered and the prevailing economic constraints.

COMPLETION SELECTION AND DESIGN CRITERIA

Well completion designs will vary significantly with:

• gross production rate; • well pressure and depth; • rock properties; • fluid properties; • well location.

Typical ranges for various classes of completions and the design implications are presented in Table 1 . This table, of course, represents a partial list of well parameters; there are many other variables that figure into a given completion design. Given the variety of production conditions around the world, definition of the thresholds is naturally somewhat nebulous (a low production rate in a Middle Eastern well would be considered a very respectable rate in many North American fields). However, this table gives a general idea of the range of design considerations.

Table 1: Completion Design Considerations

Well Parameters Design Implications

High Production Rate:

(1500-10,000 B/D liquid [160-

16,000 m3/d]; 35-140

MMSCF/d gas [1 - 4 106

m3/d]).

Significant frictional pressure losses; Large diameter tubing (>2 7/8 in. or 73 mm); Large diameter casing (>5 1/2 in. or 140 mm); Special artificial lift equipment; Thermal contraction/expansion equipment; Erosion control equipment

Low Production Rate: (<30 B/D liquid [5 m3/d]; < 1 MMSCF/d gas [30 103 m3/d]).

Artificial lift required; Paraffin buildup problems; Special attention to operating costs required.

Very High Pressure: (10,000-25,000 psi [70-175 MPa]

Special stress checks required during completion; High-strength tubulars required; Special high-performance packers/accessories required; Problems with H2S aggravated by high pressure requiring special tubular steel

High Pressure: (3000-10,000 psi [20-70 MPa]

Flanged, rather than threaded, wellheads required; Well-killing capabilities required

Low Pressure : (< 1000 psi [< 7 MPa]

Threaded wellheads may be used; Artificial lift required; Greater risk of damage/fracturing during completion process

Deep Wells: (> 10000 ft [ >3000 m]

Problems associated with high pressures; Tubular weight/tension must be considered; Casing size/liner usage must be considered; Hydraulic piston pumps or gas lift more likely to be used as artificial lift; External corrosion of tubulars may be a problem due to higher pressure and temperature

Carbonate Reservoirs: Acid wash required upon completion; Difficulty identifying water contact--need formation or drillstem tests

Very Low Permeability (<1 md): Fracturing required upon completion

Low Permeability (1-50 md): May need fracturing upon completion

Moderate Permeability ( >50 md): Little benefit from fracturing; Matrix acidizing may be necessary; Moderate pressure drawdown across perforations

High Permeability ( >1000 md ): Lost circulation a problem; Sand strength may not be great enough to support high velocity flow; Easily damaged

Unconsolidated sandstone: Sand control (screens or gravel pack) probably required

Partially consolidated and friable sandstone: (acoustic log reads >100µs/ft

[328µs/m]; compressive strength <1000 psi [<7 MPa]; (poor sidewall core recovery

Sand control possibly required; Minimize drawdown to prevent sand production; Maximize sand exposed to flow; Selective perforation required; Difficult to fracture successfully

Hydrogen Sulfide (H2S) present: Special HSE regulations/procedures; Corrosion inhibitors may be required; Gas usually considered sour if H2S partial pressure is 70.05 psia (0.3 kPa)

Carbon Dioxide (CO2) present: Consider inhibitor or special steel if CO2 partial pressure is >10 psi (70 kPa)

Water production : Scaling and/or corrosion may be a problem; Special artificial lift equipment may be required

Water injection : Consider oxygen corrosion prevention requirements; Consider backflush requirements

Well location : Offshore--Special HSE regulations; Subsurface

safety valve requirments; Well servicing and access

constraints

Urban/populated areas--Special HSE regulations;

Noise and height limits

Mountainous areas--Potential for wellhead damage

due to landslides

Functional and Well Service Requirements

Definition of the functional and well servicing requirements at the outset can

considerably simplify selection of preliminary completion concepts and will highlight

the key trade-offs needing further evaluation. Table 1 is a checklist for identifying

the critical concerns for a completion design; it illustrates the use of such a checklist

in designing a specific subsea oilwell. The completions engineer relies on experience

and judgment to prepare the initial input at the concept stage. However, as

development plans become more clearly defined, it is often possible to quantify the

requirements, based on the results of the initial wells or of detailed design or field

studies.

Completion Considerations

Importance or Need

Completion Design Implications

Rates

High None

Moderate w/chokes High favors two small tubing strings

Low Possible

Variable Critical

Pressures

High None

Low Probable artificial lift required

Producing Characteristics

Multiple zones Possible stack completions

Minimize costs Moderate review costs

Access difficulty High TFL/new technology

Uptime High minimize difficulty of future workovers

Rate control Critical chokes needed

Rate stability Critical wellhead chokes needed

Long life Unlikely carbon steel sufficient

Density of kill fluid Moderate kickoff w/gas lift

Safety during vessel reentry

Critical 2 SSSVs and kill system

Wellhead damage Possible annular SSSV

Monitoring

Test frequency High critical choke bean or dedicated

flow line

Pressure measurement

Moderate TFL access for downhole tools

Special BHP surveys Some needed TFL access for downhole tools

Log contacts Critical vertical access required

Production logs Some needed vertical access required

Tubing investigation High TFL access &/or vertical access

Artificial Lift

Intermittent w/maintenance

High gas lift is optimal method

via TFL and vertical access

Continuous Possible

Increasing gross rate High

Pressure depletion Possible

Kick-off

Initial completion Moderate use gas lift system

Routine operations

High gas compressor supply required

Depleted conditions

Possible

High water cut High

Critical rate High GLV maintenance system

Frequency High

Gas supply volume

Moderate gas compressor special requirements

Gas supply pressure

Design variable

Repairs

Cement High future concurrent production and

workover operations; easy access;

robust tubing joints

Gravel pack Critical

SSSV Probable

Tubulars Low

New interval Possible multizone completion design

Recompletions

Uphole Moderate large casing preferable

Deepen None limit depth of rathole

Sidetrack Possible maximize casing size

Function change Moderate large CSG preferable

Well Kill

Frequency High or low

operations procedure

Difficulty Mod.-high

alternate methods

Production Problems

Sand control Critical gravel pack required

Paraffin Possible TFL access for scraping

Emulsions Possible chemical injection capability

Water cut High artificial lift required

Scale Possible TFL access

Corrosion Moderate carbon steel & downhole chemical

inhibitor injection

Erosion Low

Fines Probable frequent acid jobs required

GP failure Moderate TFL w/annular kill valve

Table 1: Subsea oilwell functional requirements.

It is important for the completion design engineer to have some appreciation for the

relative impact of production revenue, capital costs, and operating costs on project

economics. In a high tax environment they are usually in the order of importance

listed above, with the revenue stream being the most critical. Installation costs are

only significant to the extent that special completion requirements have a significant

impact on the overall drilling and completion time. The actual cost of the completion

equipment is often relatively insignificant compared to the value of incremental

production from improved potential or increased uptime. However, production

engineers must not take this argument too far. It is important to remember that, in

most cases, downtime only results in deferred production. (An exception is the case

of competitive production along lease lines.) Nevertheless, for subsea developments

in hostile environments, it is reasonable to assume that a premium can be paid for minimizing the frequency of reentry and for equipment reliability and durability.

To a large extent, reservoir, geological, and economic considerations will dictate the

functional requirements of a completion and the relative significance of major and

minor workovers. These requirements have to be anticipated at an early stage since

the techniques to be employed (wireline, service rig reentry, TFL, coiled tubing, etc.) are limited by the tubing design and packer/tubing configurations of the completion.

The completion design of a well is also influenced by the well service

requirements.The general term "well servicing" covers a broad range of activities,

which can be broken down into five major functions:

1. routine monitoring (e.g., being able to run production logs, shoot fluid levels, etc.)

2. wellhead and flow line servicing (e.g., designing components for easy

isolation)

3. minor workovers (e.g., through-tubing operations, wireline work, TFL)

4. major workovers (e.g., tubing-pulling operations)

5. emergency situations (e.g., well-killing operations)

While to some extent these apply to all oil and gas developments, their relative importance, frequency, complexity, and cost are functions of reservoir conditions, governmental regulations, operating philosophy, and geographic and environmental considerations. For example, it should be self-evident that the options for reentry of subsea wells in deep water are limited and are going to be expensive. This is true to a certain extent for any offshore well. The designer must therefore look carefully at the functions that can be built into the completion and wellhead to minimize well service requirements.

It is probable that at least three different generic types of systems will be involved in

well servicing: those with functions built into the producing facilities; service units; and workover rigs.

From a completion design viewpoint, it is also important to appreciate what

capabilities are already inherently available. For example, all wells have the potential

for "bull-heading" kill or treatment fluids through the tubing, although it becomes

more difficult to control the operation and ensure an efficient displacement as the

tubing size and deviation increases. Similarly, with relatively shallow dry gas wells, it

should be possible to estimate the bottomhole pressure fairly accurately from tubing

head pressure measurements, avoiding the need to run bottomhole surveys. Another

built-in function in all offshore wells is the ability to achieve a subsurface shut-off using the government-regulation-required subsurface safety valve.

As completion designs become more sophisticated, they can provide an increased

number of integrated service functions, up to the ultimate multizone, full TFL

completion with downhole pressure monitoring capability. The economic and

technical justification for this type of completion must be based on a detailed

functional analysis of the reservoir, completion lifetime, and well service economics.

Moreover, increased sophistication also introduces higher risks of completion

problems or subsequent failures, requiring improved quality control and materials selection.

Drilling Considerations

Several drilling considerations can influence the type of completion installed,

particularly for exploration and delineation wells. Conversely, completion

considerations will help to determine drilling practices in development and infill wells. Factors to be considered include

1. Probable extent of drilling damage and the resulting requirements for special perforating or stimulation techniques, or the selection of special drilling fluids, or both.

2. The evaluation program, particularly the need for precompletion testing, to

determine if special logs or tools like the repeat formation tester (RFT) can reduce testing requirements.

3. The size and weight of the production casing. Table 1 illustrates the

limitations this imposes on the type of completion that can be installed. The

heavyweight tubular casing used in high pressure wells has reduced drift

diameters (internal diameters, or IDs) , which imposes limitations on the

packers and accessories that can be used. For example, the use of 7-in (178-

mm) production casing precludes the use of a dual tubing string with 2 7/8 x

2 7/8-in (73 73-mm) or larger tubing diameter. Depending on the

production capacities and reserves of the various producing zones, a single-string, multizone completion with larger diameter tubing may be better.

4. The burst and collapse strength of the production casing. The casing must

be able to withstand the maximum closed-in tubing pressures in case of a

tubing break at surface. Similarly, if the well is to be pumped off with an open

annulus, the casing must have adequate collapse strength. Casing strength

often dictates stimulation design, kill procedures, and selection of annulus pressure operated tools.

5. Wear or corrosion of the production casing must be evaluated in liner

completions, especially for deep wells, and, if necessary, a tie-back string

must be installed. However, use of a tie-back string may limit throughput

capacity by limiting the diameter of the production tubing.

6. In sour (H2S) environments, or where conditions could become sour,

production casing materials should conform to NACE specifications. This is

critical in deep, high pressure wells where very small amounts of H2S can result in a stress cracking risk.

7. The coupling used on the production casing needs to be carefully selected

where high differential pressures (>5000 psi or >34 MPa), high temperatures

(>300° F or >422 K), or high compressional or tensional loads are expected

(e.g., deep wells, high rate wells, thermal wells). Where a gas-tight seal is

essential (e.g., sour or high pressure gas wells or wells with high pressure

gas-lift systems), premium couplings are generally recommended.

8. Proper cementation of the production casing is the key to successful zonal isolation and avoidance of many production problems.

Table 1: Tubing size and production rate limits bas ed on casing diameter.

Casing Size Maximum Tubing Size

Maximum Theoretical Liquid

Rate*

Maximum Theoretical Gas Rate*

(in) (mm) (in) (mm) (b/d) (m3/d) (MMScf/d) (103m3/d)

4 102 2 3/8 60 2000 300 15 400

4 1/2 113 2 7/8 73 5000 800 25 700

5 1/2 140 3 1/2 89 7500 1200 40 1100

6 5/8 168 4 1/2 114 15,000 2400 80 2300

7 5/8 194 5 1/2 140 20,000 3200 120 3400

9 5/8 244 7 178 60,000 9550 »100 »2800 *IPR, THP, GLR, and conduit length often prevent such high rates being achieved in specific cases.

b. Casing Requirements for Dual Tubing

Table 1, continued: Casing requirements for dual tu bing

Casing Maximum Dual Tubing

(in) (mm) (in) (mm)

9 5/8 244 3 1/2 x 3 1/2 89 x 89

8 5/8 219 3 1/2 x 2 7/8 89 x 73

7 5/8 194 2 7/8 x 2 7/8 73 x 73

7 178 2 7/8 x 2 3/8 73 x 60

2 7/8 x 5 concentric 73 x 127 concentric

5 1/2 140 2 1/16 x 1.9 52 x 48

c. Artificial Lift Requirements

Table 1, continued: Artificial lift requirements

Casing Size Nominal Tubing Size Tubing Pump Size

Capacity†

(in) (mm) (in) (mm) (in) (mm) (b/d) (m3/d)††

Rod Pumps

3 1/2 89 1.9 48 1.50 38 550 100

4 102 2 3/8 60 1.75 44 800 150

4 1/2 113 2 7/8 73 2.25 57 1300 200

5 1/2 140 3 1/2 89 2.75 70 1900 300

Electrical Submersible

4 1/2 113 2 7/8 73 1750 300

5 1/2 140 3 1/2 89 4000 650

7 178 5 127 10,000 1600

9 5/8 244 7 178 35,000 5550

†Based on 144-in stroke and 15 spm 100% efficiency.

††Rounded off to nearest 50 m3/d.

§Based on a net lift of 3000 ft.

Specifications and Regulations

In many well completion situations (e.g., high pressure wells, deep wells, sour gas

wells, and offshore and subsea completions) the design options are constrained by

government regulations, company operating philosophies, and company design specifications.

In addition, designers are expected to conform to the standards of "good oilfield

practice," which are often embodied in agreements and regulations. Generally, this is

interpreted to mean keeping the well under control with two lines of defense, so that

a single failure or human error will not cause serious injury or environmental

damage. Typical provisions for a moderate to high pressure well are presented in Table 1.

1. During Production a. Surface

� Internal: Xmas-tree wing and master valves and offshore Xmas tree and SSSV

� External: packer and wellhead

b. Subsurface: tubing and casing (check valve and casing for side pocket mandrel devices)

2. During Drilling and Workover a. Surface

� Internal: mud/workover fluid and BOPs � External: cement and wellhead

b. Subsurface: mud/workover fluid and casing/shoe strength 3. During Lifting BOPs/Xmas Tree

a. Surface

� Internal: two plugs or SSSV and plug � External: packer and wellhead, including annular access shutoff via a

valve, plugs, or annular SSSV

b. Subsurface: As in 1b 4. Long-Term Suspension of Completed Well

a. Surface

� Internal: deep-set plug and SSSV � External: deep-set plug and packer

b. Subsurface: as in 1b 5. Long-Term Suspension of Uncompleted Well

a. Surface

� Internal: two cement and/or bridge plugs � External: as in 2a (external)

b. Subsurface: plug and casing/shoe strength

6. Temporary Suspension of Uncompleted Well a. Internal: as in 5a (internal); or casing/cement and a kill string/tubing hanger

Table 1: Typical provisions of a two-barrier safety philosophy for a moderate to high pressure well.

Even if the well has such low pressures that it tends to kill itself, wellsite personnel

should always be able to rely on a second line of defense (wellhead, BOP, etc.).

Switching off the artificial lift system or lift gas supply can sometimes be considered

a line of defense in pressure control, if this action would normally cause the well to die.

The major design specifications commonly used by the oil industry worldwide are

those issued by the American Petroleum Institute (API). In general the specifications

address the manufacture and testing of components; however, a number of Bulletins

and Recommended Practices address the performance that can be assumed for

design purposes and the procedures to be adopted in implementing that design. The

API specifications of particular relevance to completion design are detailed in

Appendix A. Materials used in sour wells should conform to NACE Specification MR-01-75.