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
High Production Rate: (1500-10,000 B/D liquid [16016,000 m3/d]; 35-140 MMSCF/d gas [1 - 4 106 m3/d]). Low Production Rate: (<30 B/D liquid [5 m3/d]; < 1 MMSCF/d gas [30 103 m3/d]).

Design Implications
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 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; Highstrength tubulars required; Special high-performance packers/accessories required; Problems with H2S aggravated by high pressure requiring special tubular steel Flanged, rather than threaded, wellheads required; Wellkilling capabilities required

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

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 Acid wash required upon completion; Difficulty identifying water contact--need formation or drillstem tests Fracturing required upon completion May need fracturing upon completion Little benefit from fracturing; Matrix acidizing may be necessary; Moderate pressure drawdown across perforations Lost circulation a problem; Sand strength may not be great enough to support high velocity flow; Easily damaged Sand control (screens or gravel pack) probably required Sand control possibly required; Minimize drawdown to prevent sand production; Maximize sand exposed to flow; Selective perforation required; Difficult to fracture successfully

Carbonate Reservoirs:

Very Low Permeability (<1 md): Low Permeability (1-50 md): Moderate Permeability ( >50 md):

High Permeability ( >1000 md ):

Unconsolidated sandstone: Partially consolidated and friable sandstone: (acoustic log reads >100s/ft [328s/m]; compressive strength <1000 psi [<7 MPa]; (poor sidewall core recovery 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) Consider inhibitor or special steel if CO2 partial pressure is >10 psi (70 kPa) Scaling and/or corrosion may be a problem; Special artificial lift equipment may be required Consider oxygen corrosion prevention requirements; Consider backflush requirements 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

Carbon Dioxide (CO2) present: Water production : Water injection : Well location :

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 Rates High Moderate w/chokes Low Variable Pressures

Importance or Need

Completion Design Implications

None High Possible Critical favors two small tubing strings

High Low

None Probable artificial lift required

Producing Characteristics

Multiple zones Minimize costs Access difficulty Uptime

Possible Moderate High High

stack completions review costs TFL/new technology minimize difficulty of future workovers

Rate control Rate stability Long life Density of kill fluid Safety during vessel reentry Wellhead damage

Critical Critical Unlikely Moderate Critical Possible

chokes needed wellhead chokes needed carbon steel sufficient kickoff w/gas lift 2 SSSVs and kill system annular SSSV

Monitoring

Test frequency

High

critical choke bean or dedicated flow line

Pressure measurement Special BHP surveys Log contacts Production logs Tubing investigation Artificial Lift

Moderate Some needed Critical Some needed High

TFL access for downhole tools TFL access for downhole tools vertical access required vertical access required TFL access &/or vertical access

Intermittent w/maintenance

High

gas lift is optimal method via TFL and vertical access

Continuous Increasing gross rate Pressure depletion Kick-off

Possible High Possible

Initial completion Routine operations Depleted conditions High water cut Critical rate Frequency Gas supply volume Gas supply pressure Repairs

Moderate High Possible High High High Moderate Design variable

use gas lift system gas compressor supply required

GLV maintenance system

gas compressor special requirements

Cement

High

future concurrent production and workover operations; easy access; robust tubing joints

Gravel pack SSSV Tubulars New interval Recompletions

Critical Probable Low Possible multizone completion design

Uphole Deepen Sidetrack Function change

Moderate None Possible Moderate

large casing preferable limit depth of rathole maximize casing size large CSG preferable

Well Kill

Frequency Difficulty

High or low Mod.high

operations procedure alternate methods

Production Problems

Sand control Paraffin Emulsions Water cut Scale Corrosion

Critical Possible Possible High Possible Moderate

gravel pack required TFL access for scraping chemical injection capability artificial lift required TFL access carbon steel & downhole chemical inhibitor injection

Erosion Fines GP failure

Low Probable Moderate frequent acid jobs required 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 (178mm) 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 singlestring, 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 based on casing diameter. Casing Size Maximum Tubing Size (in) 2 3/8 2 7/8 3 1/2 4 1/2 5 1/2 7 (mm) 60 73 89 114 140 178 Maximum Theoretical Liquid Rate* (b/d) 2000 5000 7500 15,000 20,000 60,000 (m /d) 300 800 1200 2400 3200 9550
3

Maximum Theoretical Gas Rate* (MMScf/d) 15 25 40 80 120 100 ( 3 3 10 m /d) 400 700 1100 2300 3400 2800

(in) 4 4 1/2 5 1/2 6 5/8 7 5/8 9 5/8

(mm) 102 113 140 168 194 244

*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 tubing Casing (in) 9 5/8 8 5/8 7 5/8 7 (mm) 244 219 194 178 Maximum Dual Tubing (in) 3 1/2 x 3 1/2 3 1/2 x 2 7/8 2 7/8 x 2 7/8 2 7/8 x 2 3/8 2 7/8 x 5 concentric 5 1/2 c. Artificial Lift Requirements 140 2 1/16 x 1.9 (mm) 89 x 89 89 x 73 73 x 73 73 x 60 73 x 127 concentric 52 x 48

Table 1, continued: Artificial lift requirements Casing Size Nominal Tubing Size Tubing Pump Size Capacity

(in) Rod Pumps 3 1/2 4 4 1/2 5 1/2 Electrical Submersible 4 1/2 5 1/2 7 9 5/8

(mm)

(in)

(mm)

(in)

(mm)

(b/d)

(m3/d)

89 102 113 140

1.9 2 3/8 2 7/8 3 1/2

48 60 73 89

1.50 1.75 2.25 2.75

38 44 57 70

550 800 1300 1900

100 150 200 300

113 140 178 244

2 7/8 3 1/2 5 7

73 89 127 178

1750 4000 10,000 35,000

300 650 1600 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 MR01-75.