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SPE-177557-MS

Well Completion Challenges in an Extreme Environment: A Case Study ofthe Design, Material and Completion Equipment Selection Process for

Extreme Environments

Basant Kumar Singh, Al Hosn Gas

Copyright 2015, Society of Petroleum Engineers

This paper was prepared for presentation at the Abu Dhabi International Petroleum Exhibition and Conference held in Abu Dhabi, UAE, 912 November 2015.

This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contents

of the paper have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect

any position of the Society of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written

consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations maynot be copied. The abstract must contain conspicuous acknowledgment of SPE copyright.

Abstract

Well completion design is critical for the life cycle of a well. This includes expected loads during drilling,

production, and work overs as well as metallurgical compatibility with production fluids. Any failure in

the completion has the potential to jeopardize well integrity, delay production and can potentially impact

the economics of the field development plan. There are long term studies on reliability of specific type

well completion equipment which includes over 30 years of operational experience for well systems. This

has provided a comprehensive database on well completion equipment with thousands of well-years ofproduction experience and downhole failures. However, no such data base is available for well comple-

tions with high Ni CRA metallurgy for high sour gas field development.

Al Hosn gas commenced development drilling in one of the Southwest sour gas field, located 180 km

southwest of Abu Dhabi in 2011. Phase-1 gas wells were drilled and completed in December 2014. The

well design is a single lateral, open hole reservoir completion, with the laterals being approximately up

to 15,000ft long. The well test data and logs were used to establish some of the completion equipment

design parameters including H2S 2030%, CO2 812%, salinity 160,000220,000 ppm, BHT 275 -325

deg F, FTHT 225250 deg F.

This paper highlights the work that went into completion design as well as choosing the metallurgy,

connections type, elastomers, and the completion components. In some cases, this was the first application

of the equipment in such an extreme environment. The process for designing a completion with high NiCRA Metallurgy included: 1) literature survey; 2) identifying the required standards & procedures; 3)

selection of required CRA metallurgies for required grades based on standards; 4) CRA vendor prequali-

fication; 5) validation of all CRA metallurgies by lab tests for required conditions; 6) selection of

connections; 7) validation test for CRA connections; 8) input from other operators & equipment providers;

9) strict management of change process for any deviation from specifications; 10) third party QAQC

during manufacturing and make up of sub-assemblies. The completion design integrity has been proven

under flowing condition during the well cleanups and flow testing on Phase 1 wells.

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Background and Introduction

Over the last few decades, technical and economic challenges have limited the development of extreme

sour gas fields. Increasing demand for domestic gas and advancements in technology has recently

encouraged sour gas field development within the Middle East. Al Hosn Gas, a joint venture company

formed by shareholders ADNOC and Occidental Petroleum Corporation recently completed the devel-

opment of one of the southwest high sour gas field in Abu Dhabi.

Well completion is one of the critical aspects for a successful sour gas field development. For general

understanding, the well completion is defined as the design, selection, and installation of suitable flow

conduit equipment in the well, the specification of procedures to bring the down-hole reservoir fluid to

surface and thereafter to produce in a manner which is safe, efficient, controlled and satisfies the company

objectives for the field development. This paper is written as a case study of the well completion process

used to implement for life of the field a well completion design.

Well Completion Challenges

The well completion system has to be designed fully compatible for the initial reservoir condition and also

for the changing reservoir conditions during the well life cycle. Case histories with the levels of H2S/CO2

and flow rates required were not available to use as a base case for this well completion design. The designprocess had to consider the well & reservoir parameters listed in belowtable-1.

Water production was initially anticipated to be very unlikely. However, one lower formation has

shown a high degree of natural fractures. This, in conjunction with possible acid fracturing stimulation

process increases the risk of water production occurring sometime in the well life. If water is produced,

there is uncertainty on the maximum expected level of chlorides. Offset data from other fields show

examples of up to 220,000 ppm salinity. This high water salinity will be expected to be at the saturation

limit and poses significant selection challenges for suitable CRA metallurgy at 300 deg F.

Well completion technology providers had limited tested or validated equipment and know-how for

such reservoir conditions. Some critical technology and service personnel competence gaps were iden-

tified. Additionally, no similar case histories were available for some of the equipment selection and

design process. Some of these field proven requirements were addressed with properly tailored qualifi-

cation programs. However, some of these associated limitations for such extreme reservoir conditions

increased the uncertainties and risk. These limitations were mitigated through the detailed design and

Table 1

Reservoir pressure / Temperature: 50005500 psi / 275 325 deg F

Max expected flowing tubing head pressure / temperature: 40004500 psi / 225250 deg F.

Percentage of H2S /CO2 /Salinity in produced fluid: 2030 % (pp 1375psi) / 812 % (pp 550 psi) / 160,000220,000 ppm

salinity

Completion fluid / Packer fluid: 10.8 12.4 ppg CaCl2-CaBr2 / NaCl-NaBr

pH(modelled figure with acid gas concentration): 3.29 3.64

Anticipated max production rate per well: Up to 100200 MMSCFD / well.

Inhibitor types required during field life: Corrosion, hydrate, demulsifiers, scavengers and solvents.

Carbonate high rate, high volume, high pressure stimulation for 10,000 ftlong laterals:

28% HCl gelled matrix acid treatment

Metallurgy for completion equipment / Production tubing / Production

casing (flow wetted):

High Ni CRA (high anisotropy)

Erosion concerns: Potential for erosion velocity with 2 phase flow. Minor solids production

post stimulation

Well design with production casing shoe close to top of the reservoir @

70 deg deviation:

Single & Dual laterals. Lateral lengths over 10,000 to 15,000ft.

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selection process. The remaining risks were managed by appropriately modifying the completion & well

intervention procedures.

Completion Strategy and Guiding principle

From the challenges mentioned above, it was clear that the standard well completion design and selection

process would not achieve the technical requirements. A step by step process was developed for loaddesign analysis, detailed metallurgy selection process, laboratory testing, validation process, qualification

process, detailed QAQC, fluid compatibilities etc.

All flow wetted components of the completion equipment, tubing and production liner were designed

to be made of suitably selected, tested and qualified CRA metallurgies.

Two types of well completion designs were selected after a technical feasibility study, design and peer

reviews.

The first type consisted of tubing connected directly to a permanent hydraulic set production packer in

a 9 5/8CRA production casing joint with an open hole reservoir completion. This completion type is used

for single lateral horizontal wells when not required to isolate any specific reservoir zones (Figure-1).

The 2nd type consisted of 7CRA production liner and upper completion with tie back liner top PBR:

This completion type is used for dual lateral wells and for wells requiring isolation of specific reservoir

zones for selective production (Figure-2).

Figure 1

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High level considerations applied for Well Completion Design, Selectionand Delivery process

The completion design selection process included: Initiating a literature survey to obtain similar base case;

Maintaining the principle of a simple, effective & efficient design; Utilising field proven equipment; Close

collaboration with qualified technology providers; A high level of QAQC and equipment qualification;

Detailed procedures to cover design operating envelop limitations complete with robust contingency

plans; Minimize potential flow path provision between tubing & A-annulus. The well completion

implementation steps can be summarized as: Establish the completion objectives & basis of design

(BOD); Design and select a suitable well bore completion type; Specify equipment as per design and

procure through tender; Drill the well to the approved design; Clean the well bore and displace with the

designed completion fluid; Run and install the down hole completion sub-assemblies; Initiate production

for well clean up and stimulation; Evaluate and monitor the well completion/production performance;

Address any post completion problems to maintain integrity, productivity and sustain capacity.

The first step for any well completion in a new development is to agree the objectives and BOD. There

may be some specifically required components and load conditions different for the new field. A

collaborative approach is used to review with the well completion technology providers to ensure the best

design can be achieved and also to capture any relevant technology advancements in specific areas or if

any trials are required. The global well completion database is also surveyed and used to provide case

histories to support risk assessments for the use of relatively new metallurgy, equipment, tools, acces-

sories, connections, seals, elastomers, fluids, additives, etc.

This paper focuses specifically on the well completion process for a gas field development with very

extreme reservoir fluid parameters. Data or case histories in regard to the performance of well completions

Figure 2

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in similar extreme sour reservoir conditions, which could have been used for the completion design

process base case, was very limited.

The Well Completion and Intervention scope was very challenging to achieve a long sustained life

cycle with full well integrity. The critical aspects are summarized below;

Completion BOD requirements

Maximum production rate of 100200 MMSCFD per well with a life of 25 years; Flow from all open

zones to be comingled; Minimize well interventions for CRA string & sour exposure; Memory type

down-hole quartz gauges installation provision off flow path; Condensate production of 2080 bbl /

MMSCFD; No wax or asphaltene production is expected; No water production is expected in early

life-of-field; No down hole hydrate risk is expected; No elemental sulphur is expected; refertable-1for

the wells and reservoir parameters for basis of design.

Project management approach

Pre-qualification reviews of well completion technology providers equipment were carried out for such

extreme conditions. The tender technical evaluation process was expected to take more time with several

rounds of clarifications to reduce uncertainty. The type of metallurgy, seals and equipment required for

the well completion were not available off the shelf from the technology providers. The lead-times for

such raw materials are very high in the range of 9 to 15 months. Some of the requested productqualifications procedures required a timeframe of 4 to 6 months due to the execution process and facility

availability.

The manufacturing product specifications were required to be modified for different metallurgy and

seals. The critical path method (CPM), a step-by-step project management technique, was used for process

planning that defined critical and non-critical tasks for total time optimization. The goal was to identify

and focus on critical time-frame tasks. Problems and process bottlenecks for critical items were reviewed

at every stage with the intent to prevent any escalation and to optimize the next critical item on the path.

This approach allowed validation and qualification requirements to be conducted concurrently with

manufacturing, significantly reducing the overall closure time.

Metallurgy selection for well completion equipment & tubular

As a first step, standard ISO15156-part 3 was used to select the metallurgies required for tubing,

production liner and well completion equipment. High Nickel-Chromium-Molybdenum Alloy UNS

N08028 & UNS N08825 were selected for tubing, while UNS N08825 & UNS N07725 were selected for

downhole completion equipment. Since there were no case histories available within ADNOC OPCOs for

the required metallurgy in comparable reservoir conditions, an extensive literature survey was pursued to

find similar case histories globally.

Analysis and appraisal well data had proven down-hole conditions to be in the region of 5000 -5600

psia at 275325F with 20 30% H2S and 8 12% CO2. Within the industry, there are very limited

completion design standards and papers available for this extreme environment. A few case histories

matched some parameters but not the combination of all critical parameters for metallurgy selection. In

such cases, laboratory testing became inevitable to meet the standard guideline for quality assurance and

to manage the potential high risk level with metallurgy suitability. A number of alloys were tested at a

variety of downhole and flowing conditions. Qualified labs were selected to conduct a corrosion testing

program for material qualification and establish suitability for use under reservoir and surface flowing

conditions.

Three types of tests (constant load C ring bent beam and slow strain rate) were conducted for full

evaluation. Testing had shown that alloys UNS N08028 and UNS N08825 were functionally equivalent

at design conditions. Additional testing was carried out on other alloys including SM 2535, SM 2550,

UNS N07718, UNS N07725, and UNS N09925. There was no commercial advantage for either SM 2535

or SM 2550 over UNS N08028 or UNS N08825, so these alloys were not tested to the full range of

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conditions used for testing alloys UNS N08028 and UNS N08825. Alloys UNS N07718, UNS N07725,

and UNS N09925 were tested and qualified for use as tubing hangers, sub-surface safety valves,

production packer, profile set plugs and other well completion equipment. Some limitations were

identified for alloys UNS N08028, UNS N07718 and UNS N09925 by this testing program. Review of

the laboratory and literature data were conducted to support selection of the suitable alloys for the given

condition.

NACE type 4c and 4d tubular materials provided acceptable SCC behavior in the simulated serviceenvironments: Type 4c UNS N08028, N08825, SM2535 and Type 4d SM 2550. This program

involved the use of three different types of tests (C-ring, bent beam and SSR) and multiple heats of the

Type 4c materials (UNS N08028, N08825 and SM 2535) were used. All NACE Type 4c tubular materials

included in the evaluation program exhibited similar SCC resistance as would be expected from their

listing in NACE MR0175/ISO15156 Part 3 Table A.12. In fact, all three materials evaluated in the

program actually exhibited greater SCC resistance in terms of higher temperature and H2S partial pressure

limits than the limits indicated in NACE MR0175/ISO15156 Table A.16.

Similar tests were conducted with another laboratory to independently validate the results and further

close the uncertainty when more detailed reservoir parameters were established. Reservoir data indicated

elemental sulfur would remain dissolved in hydrocarbon condensate and max expected salinity up to

220,000 ppm. For this salinity and expected temperature, both alloy UNS N08028 and Alloy UNS N07718were not found fully suitable. After all these tests, the final selections were made:

Nickel alloy UNS N08825 recommended and used for 7 and 5 production tubing material.

Nickel alloy UNS N07725 and alloy 625 plus (N07716) are recommended and used for the

completion equipment & accessories.

Production Tubing Size

Well rate, PI, well interventions and other relevant requirements were reviewed for different tubing sizes.

Tubing size of 5 was selected for the following key reasons:

a. The restricted flow rate of the wells to 80 MMSCFD due to gas gathering equipment limitations

thereby eliminating the key advantage of 7 tubingb. The rate will drop off over time due to natural pressure decline

c. Intervention and isolation in the reservoir is not a primary requirement for the wells and is not

planned thereby eliminating the need for a mono-bore type completion design with 7 tubing.

Selection of connections for CRA tubing and completion equipment

Premium gas tight Cal IV qualified connections were required for the production tubing and completion

equipment. Pre-qualification was carried out with the vendors to assess the technical capability and track

record ability to provide the CRA tubing and qualified premium thread connections with the required

metallurgies. However, the premium connections from the qualified CRA tubing vendors were not

qualified for the size, weight, grade and metallurgy type. To achieve the required quality assurance,

qualification tests (as per ISO13679) were required to check the seal performance, galling resistance and

mechanical strength performance for the required class. These tests were conducted with specific facilities

for CRA metallurgy with over 6 months lead-time and higher cost. Being a critical aspect for well integrity

assurance for life of the well, all the connection qualification tests were conducted for 729ppf and 5

20ppf p-110 connections with high nickel alloys UNS N08028 and SM2535 for the Cal IV qualification.

High nickel CRA pipes and connections are susceptible to damage during handling and make-up and

require specific procedures. Learnings from the tests were used to improve the anti-galling properties for

the connections and to provide fit for purpose connections. Later, when the metallurgy was changed to

UNS N08825, a critical requirement was to re-qualify the connections, while keeping in view the

associated higher cost and lead-time. In this case, the only change was the alloy chemistry for better

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temperature suitability. Other mechanical parameters of these connections were unchanged and the

metallurgy remained in the same NACE type 4c materials class. Hence, with this rationale and with a

limited timeframe before the start of the drilling campaign, the connections with UNS N08825 were

accepted to allow tubing and completion equipment to be delivered in time. Operational data to date have

shown that these connections have performed satisfactory during completion running, completion testing

and well production phases. Some galling issues have been observed during retrieving for work over jobs,

but these have been limited to only a few joints.

Rubber Elastomeric Seals

To establish suitable rubber elements & elastomeric seals for this extreme environment coupled with high

mechanical loading was very challenging. For the given well and reservoir fluid parameters, the required

rubber elements and seals according to ASTM D1418 designation are FEPM, FFKM & PEEK type. All

elastomer or rubber materials were tested in accordance to the latest editions of the ASTM D for tear

resistance, tension, hardness and environmental effect for the confirmed conditions. Equivalent elastomers

with different trade names were used from qualified providers. One seal system with a good track record

is either Kalrez or Aflas moulded onto a deformable body with Chemraz and peek for v seals. All these

seals were tested to V2 or V0 class to qualify as required on the specific items.

Tubing stress and load analysis

The Tubing stress analysis was conducted using the industrys standard Landmarks wellcat software -

Build 5000.1.7.0.11180. The initial tubing stress analysis was conducted with 5 20ppf & 729ppf 110

CRA UNS N08825 tubing with VAM TOP HC and Tenaris blue connections. Initial tubing stress analysis

was further verified with external engineering specialists for the well and completion design. The work

evaluated the effect of transient temperature, pressure, tensile and compressive loads. It was ensured that

the selected tubing remain within the acceptable tri-axial, axial, burst and collapse design safety factors

for all expected combined loads. The design limit plot and tri-axial stress safety factors plot are shown at

figure-3andfigure-4for reference.

Figure 3Tri-axial design limit envelope

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Key design parameters and assumptions for various load cases were as follows: Well-path ofapproximately 50 to 55 degree well deviation at 9 5/8 production packer setting depth used for

approximate well trajectory; 2 degree dogleg superimposed over the full well profile; kill weight brine of

11.7 ppg; packer fluid of 11.7 ppg brine; frac fluid of 11.7 ppg; acid density of 8.82 ppg; ambient

temperature of 80 deg F; setting depth 11,938ft MD / 10,880ft TVD (upper completion); well temperature

of 275325 deg F at 11,000ft TVD; maximum reservoir pressure of 5,500psi; CGR of 2080 bbl /

MMSCFD; WGR of 3 bbl / MMSCFD (this is the minimum water of condensation calculated by flow

modelling software); maximum production rate of 100 MMSCFD / well; surface bullhead acid stimulation

required at maximum possible rate of 45 BPM.

Some technical challenges were observed for stress and load analysis in this type of extreme

environment with high end Ni CRA alloys. The critical aspect is that the design process is based on

assumption that material mechanical properties behave in uniform manner, i.e. the yield point of material

is same in all directions. Many CRA materials exhibit an-isotropic properties, i.e. different mechanical

properties in different directions. This variation becomes wider for high nickel alloys and the cold worked

alloys. The variation is also manufacturer dependent due to variances in manufacturing processes and end

treatment. The axial yield stress can be determined by lab testing. However, the tangential and radial

properties are lower and a dedicated specific experimental process is required to establish these properties.

Selected CRA metallurgy suitable for the corrosion aspect in this environment is UNS N08825. This

metallurgy cant be heat treated and only cold worked to achieve the required mechanical yield strength.

In general, longitudinal tensile is the standard method to determine the mechanical properties of the

material. Experience and actual tests show that cold worked CRA materials may show longitudinal

compressive yield strength as low as 80% of the longitudinal tensile measurement. This anisotropy

property of CRA metallurgy poses a lower compression strength working envelope with no expansion &

contraction manipulating devices like free floating PBR or expansion joints. The mechanical strength and

properties of CRA materials are temperature dependent and varies for each CRA metallurgy from different

vendors. The yield strength and density variation were required to be experimentally established and used

for design. The yield strength rating of UNS N08825 varied from 100% at ambient temperature to about

86% at 300 deg F.

A sensitivity analysis was carried out to determine the maximum expected flowing wellhead temper-

ature. This was initially conducted to verify down-hole material grade specification. However, it was also

important for surface system design and surface system flow modelling. As the CGR increases, the flow

Figure 4Tri-axial design safety factors

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rate will drop for a given reservoir pressure. As the CGR increases the U value will decrease thereby

giving a lower average tubing temperature. This in turn will result in lower axial compression in the

tubing. For this reason, a CGR of 20bbl/MMSCFD was assumed as worst case load.

Packer forces and movement analysis

The completion strategy for these extreme sour gas wells was not to use the commonly installed free

moving dynamic PBR type seal system due to significant expansion and contraction of the completion

string across the operating envelope. In the first type of completion design chosen, the production packer

was integral to the production tubing with thread connection. In second type of the completion design, the

seal assembly of the PBR is anchored with shear latch rated at 200,000 lb. Tubing to packer force analysis

was carried out by two different teams to ensure all the loads were considered and also provide cross

validation for worst case design loads (Figure-5).

The max expected tensile and compression loads from these two independent analyses were calculated

by design models and are listed in belowtable-2;

Figure 5

Table 2

Max expected Loads

Load analysis by one

source

Load analysis by second

source

Packer force rating for

procurement Tender

Compressive loads: Tubing evacuation &

Depleted production

Load:275,000 lb & 5718

psi diff from above.

Load:251,000 lb & 6000

psi diff from above.

Load: 275,000 lb in

compression (tubing

evacuation).

Tensile Loads: High rate Stimulation &

Well kill

Load:230,000 lb & 3000

psi diff from below.

Load:253,000 lb & 3000

psi diff from below.

Load:250,000 lb tensile

(Stimulation).

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The Design Factor of 1.6 has been used for both tensile and compression rating of the packers.

However, the actual Safety Factor is 2.9 for tensile loading and 2.67 for compression rating for the

permanent HPHT packers used for the completion of phase-1 development wells. Additionally, external

verification was obtained on inputs for the expected packer loads with the Cyber-String application. The

result indicated no issues with all expected load conditions.

The primary results from the stress and load analysis

The selected tubing and completion components from the tubing hanger to the top of the production

packer were designed within the required design factors for tri-axial, axial, burst and collapse loadings.

The designed acid stimulation job required high pressure pumping to achieve the maximum rate required

for longer open-hole lateral sections. However, the tubing connected packer design allowed only 3000psi

differential pressure from tubing to annulus. The operational procedure was implemented to include the

application of pressure in the A-annulus during stimulation and also installing PRVs on both annulus and

tubing side.

Production packer qualification

Type 1 - Hydraulic set tubing connected permanent production packer: Single-trip, hydraulic set,permanent production packer (material alloy UNS N07725). Run on production tubing size 5 1/2, 20ppf,

Tenaris blue or Vam top HC connection, alloy UNS N08825-110 grade. Set inside production casing 9

5/8, 53.5 ppf, alloy UNS N08028-110. A 6.5k psi differential pressure rating in both directions.

Temperature rating of 350 deg F, suitable for extreme sour environment gas with 26% H2S, 10% CO2,

220,000 ppm chloride. An integral one piece mandrel to minimize leak points with the elastomer qualified

for extended sour service exposure, barrel type upper & lower slips for CRA casing, expanding extrusion

barrier, milled & retrieved on packer picker. A three piece multi duro packer element with large packer

ID to minimum of tubing ID and minimum number of pressure seals points on piston. The tubing to packer

force safe working envelope for 275,000 lb in compression (tubing evacuation) & 275,000 lb tensile

(stimulation & well kill). The primary criteria for the 9 5/8 production packer was to have high enough

tensile and compressive strength to meet worst case load scenario during stimulation and production phase

for life cycle of the wells.

Type 2 - Mechanical packer and anchored PBR seal assembly system: The seal anchor shear rating was

limited by the drilling or work-over rig safe over pulling capability. For this reason the seal anchor latch

shear was limited to 200,000 lb plus tolerance of- 25,000 lb. Although the mechanical production

packer was designed for full load of 275,000 lb, the seal anchor latch limited the tensile load capability

to 200,000 lb plus tolerance of- 25,000 lb.

It was desired to use field proven production packers. However, none of the technology providers had

field proven 9 5/8 production packers with alloy UNS N07725 in similar environment or with qualifi-

cation tested to V0. Bids were invited from pre-qualified completion equipment providers with condition

that successful bidder will qualify these packers for V0 environment. The qualification time was includedin the delivery periods with no impact to overall project time for well delivery. Packer qualified operating

envelop with V0 testing exampleFigure-6as below.

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Tubing retrievable surface controlled Sub-Surface Safety Valve (TRSCSSV)

Tubing retrievable and self-equalizing type safety valve TRSCSSV was selected with the objective to

provide a downhole well control barrier for the production phase and provide a fail-safe protection

mechanism should the wellhead be knocked or damaged. Other main consideration was to use 7

TRSCSSV for 5 well completion design. This enabled the use of an isolation sleeve and nipple

protector sleeve across the TRSCSSSV during bullhead acid stimulation. This also enabled coil tubing and

wireline interventions with full size flow control devices for 5 completion string. Rigorous QAQC was

applied and valves were tested to API14A and ISO 9001. The TRSCSSV with alloy UNS N07725 wasqualified with all requirements in API 14A, Service Class 2, 3 (3S & 3C) and 4. The TRSCSSV actuator

system was designed with dual seals to prevent commingling of wellbore and hydraulic control line fluids.

The design requirement is for true metal-to-metal (MTM) seals at valve open and closed positions and

Non-Elastomeric material dynamic seals. The TRSCSSV flapper and seat have a primary MTM seal

against wellbore fluids, while the body connections incorporate a MTM seal. The TRSCSSV was tested

and qualified to be capable of maintaining pressure differential across the flapper, re-open and close

within acceptable limits and maintain operability after an erroneous closure at high gas flow rates. For

blow-out gas flow rates, the TRSCSSV was tested to maintain pressure differential across the flapper and

then re-open within acceptable limits. Tests were conducting using the maximum anticipated production

flow rates of 100 MMSCFD at 1000 psi. The blow-out condition was tested for 175 MMSCFD through

the 7 TRSCSSV. Upon completion of the gas slam testing, the TRSCSSV were inspected for damage,critical dimensions recorded and valves were qualified.

Packer Fluid

Clear filtered inhibited brine is always preferred as packer fluid of producing wells. This fluid is selected

to be compatible with all metallic and seal components and for corrosion aspect. The required brine weight

for these wells were about 11.8 ppg which is above the normal critical density of 11.5 ppg. Many potential

issues are known for the brines above 11.5 ppg and at higher temperatures. These include effective

corrosion inhibition, precipitations, handling, divalent salt effect etc. The completion metallurgy of UNS

N08825 and UNS N07725 are not known to have any potential corrosion issues with CaCl2-CaBr2 or

Figure 6

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NaCl-NaBr brine for this weight and temperature range. However NaCl-NaBr brine is preferred and for

economic reason was selected for packer fluid.

High Ni CRA Intervention tools and down-hole gauges

With Phase-1 strategy to use minimum penetrators and seals in the completion string and wellhead,

down-hole memory gauges were required. For increased such intervention runs in the well, it was critical

to minimize CRA contact to carbon steel. Hence it was selected to use high Ni CRA tools and accessories,

CRA Deep set profile plugs, CRA soft set gauge hanger and CRA down hole memory gauges for the CRA

completion. The reservoir / well surveillance campaign was initiated successfully and learnings were

captured on handling of the CRA tools for sustained operation. Based on these learnings, it is being

proposed to primarily use permanent down-hole gauges for phase-2 development.

Equipment suitability & integrity with rigorous QAQC program

Reliability was the key driving factor for these high value critical wells in such extreme sour conditions.

A rigorous QAQC program was essential for successful well completion operations and long term well

integrity. This applied to all four phases of well completion delivery process which are Design,

Manufacturing, Installation and Operation. The completion design was analyzed, reviewed and verified

internally. The design was further vetted by external engineering specialists and also by the technology

providers. Q1 quality level with third party inspection requirements were applied to manufacturing stageand the assembly process. For installation phase, sub-assemblies were prepared in workshop with

dedicated supervision, tested for the required conditions and all parameters recorded for future reviews if

required. Field completion specialists were utilized at the rig site to oversee installation. The completion

well on paper exercise was carried out involving all the service providers with office and field

representatives to capture and address any design or operational gaps. The completion was designed for

minimum interventions in the wells and only interventions planned were for well integrity and minimized

pressure surveys.

Gaps & limitations with the technology and resources availability

Long and uncertain lead times were faced for the specific materials availability and for the

qualification tests process with all the global pre-qualified technology providers.

Limited or no field proven data was available for some high Ni CRA metallurgy equipment for the

expected load conditions and environment experienced by a well completion (for example

production packer, connections, intervention tools, lateral access tools etc).

No coiled tubing manufacturers were known to produce coiled tubing reels made from this class

of CRA materials. There were few case histories where chrome CRA coiled tubing had been used

in completion jobs, but none for intervention operations like those proposed for these wells. The

reason was due to the poor pipe fatigue life for high Ni CRA pipe. For the sour environments,

Operators and CT service providers usually use carbon steel CT pipe (normally grade 80 ksi)

equivalent metallurgy manufactured under the recommended guidelines for the material with

manufacturing and testing process controls as per API specifications 5ST for sour service

conditions. This was used with some applied limiting factors like reduced CT pipe life, real time

monitoring of CT pipe condition, limited available exposure time in down-hole condition based on

actual lab tests data, etc. The sour service carbon steel 2 3/8 coil tubing pipe grade T95 was

extensively lab tested for this high sour environment. However, the lab test results provided only

maximum 6 hours exposure time for acid stimulation which drastically reduced intervention scope

in the long lateral horizontal section.

High CRA alloys are known for heterogeneous and anisotropy behavior under different conditions

like tensile, compression, temperature etc. This necessitates establishing the actual mechanical

resistance of the selected CRA metallurgies for required operating condition envelope. These

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parameters were not readily available and were vendor specific. These properties needed to be

established to a high degree of confidence through experiments and testing, which incur additional

cost and time. These accurate values of anisotropic change and temperature were required to be

applied to mechanical properties to achieve more accurate mechanical design analysis with respect

to varying mechanical resistance of that particular CRA metallurgy for different load cases.

Limitations of effective corrosion inhibition were faced for stimulation with high strength acid in

sour gas environment at high temperature. Lab tests were conducted with various corrosioninhibitors for given conditions at high temperatures. The inhibition was effective for the majority

of the well depth, but did not provide effective inhibition at static bottom hole temperatures in the

reservoir section in presence of high sour environment.

Final well completion design and acceptance process

With the above outlined strategy and approach, the design was successfully established, loads analyzed

and the well completion equipment with all accessories selected. The detailed design was peer reviewed

and also vetted by external specialists.

Conclusions & PerspectivesThe project is currently producing to full processing capacity with full well integrity, production

efficiency and all conformance. The well completion challenges, available technologies and the process

followed here can contribute to a better understanding of the well completion requirements for such

extreme reservoir conditions. Results of this case study could provide some guidelines for well completion

design and selection process for field development of similar sour fields.

AcknowledgementThe author would like to thank Al Hosn Gas, ADNOC and Occidental management for the permission and

encouragement to publish and share this paper with the industry. The author would also like to thank Tod

Stephens for all clarifications from drilling perspective and to Medhat Al Habsi for sharing his regional

sour wells experience from other ADNOC OPCOs.

Nomenclature

A-annulus Annular space between production tubing and production casing.

ADNOC Abu Dhabi National Oil Company.

ALARP As low as reasonably practical.

Bbl Barrel.

BHT Bottom hole temperature.

BOD Basis of design.

CaBr2 Calcium bromide.

CaCl2 Calcium chloride.

CGR Condensate gas ratio.

CO2 Carbon Dioxide gas.

CPM Critical path method.

CRA Corrosion Resistant Alloy.

CT Coil tubing.

Deg Degree.

EAC Environment assisted cracking.

F Farenheight

H2S Hydrogen Sulfide sour gas.

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HCl Hydrochloric acid.

HPHT High Pressure High Temperature

ID Internal diameter.

Ksi Thousand pound per square inch.

Lb Pound.

MD Measured depth.

MMSCFD - Million standard cubic feet per day rateMTM Metal to metal .

NaCl Sodium chloride.

NaBr Sodium bromide.

Ni Nickel.

NOC National oil company.

OPCO Operating company.

PI Productivity Index

PBR Polish bore receptacle.

PBTD Plug back target depth.

Ppg Pound per gallon.

Ppm Part Per MillionPp Partial Pressure

PRV Pressure relief valve.

Psi Pound per square inch.

QAQC Quality assurance and quality control.

SCC Stress corrosion cracking.

TD Target depth.

TRSCSSV Tubing Retrievable Surface Controlled Subsurface Safety Valve

TSA Tubing Stress Analysis.

TVD True vertical depth.

UAE United Arab Emirates.

WRM Wells and reservoir monitoring.

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