238285043 Well Integrity Management System WIMS 00088696

SPE 88696 Well Integrity Management System (WIMS) ZAKUM DEVELOPMENT COMPANY (ZADCO) ABU DHABI, UNITED ARAB EMIRATES Jamal Al- Ashhab, Mohamed Afzal, Dr. Cornelius O. Emenike Copyright 2004, Society of Petroleum Engineers Inc. This paper was prepared for presentation at the 11th Abu Dhabi international Petroleum Exhibition and Conference held in Abu Dhabi, U.A.E., 10–13 October 2004. This paper was selected for presentation by an SPE Program Committee following review of information contained in a proposal submitted by the author(s). Contents of the paper, as presented, have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material, as presented, does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Papers presented at SPE meetings are subject to publication review by Editorial Committees of the Society of Petroleum Engineers. Electronic reproduction, distribution, or storage of any part of this paper for commercial purposes without the written consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to a proposal of not more than 300 words; illustrations may not be copied. The proposal must contain conspicuous acknowledgment of where and by whom the paper was presented. Write Librarian, SPE, P.O. Box 833836, Richardson, TX 75083-3836, U.S.A., fax 01-972-952-9435.

ABSTRACT ZADCO owns more than 500 wells operating in UZ, UA & ST fields to contribute in achieving the production targets as set by the Shareholders. To ensure that wells operate as designed for their assigned life (or greater) with all risks kept as low as reasonably practicable or as mentioned, it is important to insure individual well’s integrity. Hence, ZADCO developed an in-house “Well Integrity Management System (WIMS)”, which defines & provides the operating standards & guidelines for maintaining the well integrity parameters, ensuring safe well operations and securing well potential availability during its life cycle so that return on investment is maximized without the sacrifice of safety and environment. The implementation of ZADCO’s well integrity process follows the cycle assurance testing, preventive measures, monitoring, evaluation / assessment, control & remedy, audit / verification. This paper reviews WIMS in ZADCO. WIMS is structured to include wellhead (surface) equipment, downhole equipment and operational (process control). WIMS places much emphasis on the requirement of barriers for safety and environmental protection. Key Words: Well Integrity Management System, Well Barriers, Wellhead Equipment, Sub-surface Equipment, Scale & Corrosion Management, Risk Management.

INTRODUCTION: The objective of developing Well Integrity Management System (WIMS) is to provide standard guidelines to ensure that technical integrity of all the wells is maintained throughout their life cycle, they operate under safe condition and are capable to function continuously to achieve the targeted production/injection requirements. Well integrity is based on the establishment and maintenance of confinement barriers in the particular well. As per WIMS standards, a well is considered integral if at least two separate and sound confinement barriers across each flow path between the potential reservoir and surface are available all the time. WIMS very much emphasis on the problem prevention based approach (endeavour to predict & solve the problem before it happens) that can accommodate several direct advantages and benefits like reduction in operating down time, enhancement in well control and safety aspects, minimized unplanned repair intervention & cost impact etc. Major well issues that would have impact on the technical integrity and operability of a well viz; Surface Completion Components (Wellhead & X-mass tree), Sub-surface Completion Components (downhole safety valve (DHSV), Gas lift valves, electric submersible pump (ESP), Well Construction (Casing & Annulus), Communication Problems, Corrosion, Scaling, Nonhydrocarbon Effluents / Products, Well Operation Suspension, Well Intervention Services (Electric/Slick Line, Stimulation, coiled tubing unit (CTU), Risk Management Process & Auditing System, etc. have been thoroughly discussed in the WIMS manual. WELL BARRIERS: The barrier is a protection measure to prevent an uncontrolled release of hydrocarbons to surface via production strings or from reservoir to well annulus. Primary barriers always control immediately the well’s up-stream side pressure, whereas secondary barriers, which normally have no well-bore pressure against them, immediately supplement the primary barriers (Fig.1). A barrier that loses its integrity is classified as

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non-integral barrier provided that a visible leak is detected in the surface barrier or if the maximum operating pressure in wellhead component exceeds its working pressure or the H2S contents in the annulus fluid exceeds the NACE MR01-75 conditions. Corrosive environment, non-compatibility of elastomers with well effluents, leak rate and higher temperatures are the major factors that affect the resistance of the structural barrier (Annulus).

Seals Integrity: •

For gas wells, tubing hanger ‘s metal-to-metal neck seal should not be tested from x-mass tree flange as it may cause the seal to collapse. However, the same port can be used for monitoring purpose. It is advisable to approach the concerned vendor for proper seal integrity test.

•

The test pressure for tubing hanger seals is recommended to be equivalent to the working pressure of x-mass tree. However, in case of casing hanger seals, 60% of the concerned casing collapse pressure is considered as the test limit.

•

Hydraulic oil is recommended to be the test medium and constant readings for 10 minutes of the test pressure are considered as the acceptance criteria for each test.

•

Check valves from any of the port should never be removed unless pressure behind it is zero.

WELL BARRIER ENVELOPE

PRIMARY BARRIER

SECONDARY BARRIER

X-MASS TREE

EXIT TO TEST SUB SEAL TUBING HANGER SEALS

RING GASKET NEEDLE VALVE PRODUCTION ANNULUS CONTROL LINE

DOWN HOLE SAFETY VALVE PRODUCTION CASING TUBING STRING KILL FLUID

Performance Testing of Static Components:

9 5/8” DUAL PKR

7” LINER TOP

CEMENT FLOW UPPER ZONE 7” PERMENANT PKR

Gate valve bodies, crosses, tees, tubing/casing hangers and every cavity that exists between several components are classified as static components. These components can be tested hydraulically or against wellhead shut-in pressure and the acceptable criterion should be no visible leak detection. Testing frequency for static components is recommended to be the 2 years, irrespective of any test procedure.

FLOW LOWER ZONE

Performance Testing of Mobile Components: Fig. 1 Well Barrier Envelop

WELLHEAD COMPLETION MANAGEMENT: Wellhead and X-mass tree play a vital role in controlling the well flow. It is therefore quite necessary to test/assure the integrity of all the components including valves & seals. Special attention to gas wells’ surface components is considered mandatory. The performance monitoring, testing and remedial work data should be recorded in the prescribed forms as provided in the WIMS manual. Key guidelines and test procedures are highlighted as following: Gate Valves Integrity: •

Wellhead shut-in pressure and well fluid are to be used as test medium and the test duration should be minimum 15 minutes.

•

Bubble test is to be considered as the acceptance criteria for gas wells. However, leak rate should be evaluated before further action is taken.

•

Leaking valves are to be greased to confirm the test results.

The gates, seats, stem packing and gate valve plugs are classified as mobile components. These components can be tested hydraulically or against wellhead shut-in pressure. In case of hydro test, 110% of the maximum expected operating pressure of the component and in other cases; maximum achievable wellhead shut-in pressure for 10 minutes at least is considered the test limits. The acceptable criterion should be no visible external leak & zero pressure drops. Testing frequency for x-mass tree valves is recommended to be the 6 months and for annuli valves to be the one-year. Valves Integrity Failure Causes & Cures: Malfunction

Cause

Cures

Wells pressure leaks past valve. Line fluid leaks between valve body and bonnet. Downhole eqpt. will not

Valve gate and seat leak / are not installed properly Bonnet gasket leaks.

Disassemble the valve and reinstall the gate and seat.

Valve gate not aligned

Tighten the bonnet nuts. If leak persists, replace the bonnet gasket. Disassemble the valve and adjust

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pass through open valve. Valve “jumps” open when pressure is applied to actuator. Valve does not close.

Will not open or close.

Hard operate.

to

properly. Excessive pressure differential across valve gate. Pressure remains in actuator cylinder. Excessive friction on gate. Hydrates or ice in valve body. Insufficient lubricant. Restriction body cavity.

in

Erratic operation.

Iced up due to restricted flow, hydrates or low temperatures. Accumulation of mud, sand or other foreign matter in valve body. Stem threads damaged. Shear pin dragging on bearing cover. Stem or stem nut is broken or threads are stripped. Sheer pin is broken. Gate not properly aligned with bore of seats. Stem threads damaged.

Leaking bonnet flange. Leaking around stem.

Bearing needs to be lubricated. Bearings are broken. Leaking bonnet seal ring. Packing and/or stem damaged.

Will not seal

Worn

Hand-wheel not working.

Restriction in bore of valve.

or

gate position on stem. Pressurize downstream flow line to approx. 75% of existing well pressure. Bleed off actuator pressure. Lubricate valve.

the

Warm the valve body to melt hydrates See lubrication instructions. See venting and lubrication instructions. Work hand-wheel back and forth sharply. If ice or hydrates, apply heat before venting and lubing. Vent and apply heat to valve body. (Do not use an open flame). See venting and lubrication instructions.

Grease fitting leaking.

Call field control center (FCC) representative. Replace sheer pin. Stroke valve fully several cycles from full open to full close position. Back up from hard operating spot before continuing in one direction. Replace when practical. Lubricate bearings. Replace bearings. Replace seal ring. Replace packing or stem as needed. Replace worn

Tighten cap replace fitting.

or

Preventive Maintenance: Preventive maintenance is aimed at maintaining the wellhead equipment as per procedures specified by the manufacturer, extend the components life cycle and avoid harsh fluid entrapping inside gate valves cavity. Preventive maintenance is further divided in two categories viz routine-based and non routine-based. Routine-based preventive maintenance at regular interval is purposed to flush out the sludge/debris from body cavity and provide lubrication to valve stem threads, bushing & gate/seat sealing surface in addition to protection against corrosion. On the other hand, non routine-based preventive maintenance is purposed to protect the x-mass tree and valves internals from the expected corrosion attack as result of stimulation, killing, injection and descaling or polymer treatment operations. General guidelines for the preventive maintenance are highlighted as following: •

No job to be started without work permit.

•

Cathodic protection system to be removed and remote operating system to be bypassed prior starting maintenance job.

•

Greasing pressure should never exceed the working pressure of the valves.

•

The type of grease to be used as per API standard and the amount of grease and application procedures to be followed as per concerned equipment manufacturer’s recommendation.

•

It should be ensured that grease flows through valve cavity.

•

All wells to be treated as hazardous and never attempt to remove or tighten any thing under pressure.

•

Proper inhibitor to be used to flush out the valve cavity after each stimulation job.

Repair or replace. Realign pin.

Safety cap not on tight enough.

Hydraulic Actuators Preventive Maintenance: Hydraulic actuators are the most important components with respect to their response (quick opening or closure) against any abnormal or normal situation. Therefore, implementation of an effective periodical preventive maintenance program can ensure their integrity and smooth operation. It is recommended that all the actuators must be function tested every 3 months and they must close with in 30 seconds.

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SUB-SURFACE COMPLETION MANAGEMENT: Sub-surface components of any well construction play an important role in well operation & well safety. It is therefore considered necessary to ensure that subsurface components of a well functions properly and their integrity remains intact through out their life cycle. Description of key sub-surface components and the standards/guidelines to test assure their integrity is discussed as following. Down Hole Safety Valve: Two types of down hole safety valves viz surface controlled sub-surface safety valve (SCSSV) & subsurface controlled sub-surface safety valves (SSCSSV) are in place to control the well flow during any abnormal situation. SCSSV type valves, either tubing retrievable or wireline retrievable, operate to open by hydraulic pressure applied to a piston valve via control line and close by a counter acting spring. On the other hand, SSCSSV type valves like velocity valve (storm choke) & injection valve operate to close directly by the abnormal behavior of produced or injected fluid. It is recommended that open/close function of the down hole safety valves to be checked every 3 months and pressure test performance (bleed off above valve) to be reviewed every 6 months. The degree of DHSV integrity depends on the observed leak rate, which can be calculated as per Eq.1. Q = 60*{(P2-P1) / (T2-T1)}*V …… Eq. 1

Where, Q P2 P T2-T1

= = = =

V

=

Leak rate in SCF/hr Final pressure in psig Initial pressure in psig Time in minutes when pressure increases from P1 to P2 Volume in cubic feet

Leak rate of 6.3 USG/hr. for oil wells and 400 USG/hr. for water wells is considered to be acceptable. In case of gas wells, acceptable leak rate depends on tubing size. For example, 124 psig/hr. pressure build-up in a 3 ½” tubing is considered acceptable in ZADCO. Any test failure is to be recorded in the prescribed ‘Failure Report’ form as provided in the WIMS manual. Preventive Maintenance: In order to avoid any risk in operating DHSV due to any solids, scale or asphaltene deposition on its body or due to packing deterioration, it is imperative to replace the DHSV every year in gas wells and every 2-3 years in oil or water wells. Besides, every time when the DHSV is pulled out of hole during any down hole operation, it must be thoroughly inspected, serviced or even replaced if its overall condition is found deteriorated. DHSV should be repaired and function tested in an

API approved workshop as per API standards “API Spec. 14A”. Gas Lift Valves: Gas lift valves are the key components of any gas lift well’s construction. Prior to the installation of any gas lift valve, its integrity should be ensured according to API Spec. 11V1 by performing different tests e.g. bellows assembly test, stem-seat test, reverse flow valve leakage test etc. All these tests should be performed in accordance to manufacturer’s specification & procedures. As a first step towards post-completion integrity preventive measures for new wells, where tubing and annulus are both filled with completion fluid, it is highly recommended to strictly follow the standard unloading procedures. In case of the already unloaded wells, same procedures are normally applied but with certain deviations like casing pressure can be increased fair rapidly as no completion fluid exists in the annulus and the well kicks off much quicker. It is important to establish a track record of the gas lift valves usage history and maintenance data. Whenever the gas lift valves are retrieved for repair or replacement purpose, ‘Failure Report’ form, as provided in the WIMS manual, shall be prepared. SCALE MANAGEMENT: The objective of scale management is to define the preventive, corrective and monitoring policy to prevent, treat and control the scale deposition and behavior in UZ wells. Normally two major types of scale deposits are found across the tubing strings in Zadco wells, which are hard and solid state in shape (Fig. 2) 1. Strontium Sulfate (SrSO4) represents approximately 70% of the overall scale deposition cases. 2. Calcium sulfate (CaSO4) represents approximately 25% of the overall scale deposition cases. 3. The remaining 5% scale deposition cases comprised of miscellaneous such as carbonates and corrosion by products. The main cause of such scale deposition in the producing wells is the incompatibility between the formation water (enriched with minerals) and injected seawater (enriched with Sulfates / Carbonates). Scaling phenomena occurs due to reaction between the minerals & Sulfates / Carbonates when the injected seawater breaks through and mixes with formation water accompanied with change in thermodynamic conditions. Scaling Impact on Well Integrity: Technical integrity of tubular is badly affected with scale

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deposits as it causes the cross sectional flow area of a string (ID) to reduce or completely plug off, which ultimately results in partial or total production loss. Safety barrier integrity by eliminating the functioning of, down hole safety valve (DHSV) and the check valve (NRV) installed at the surface flow lines, is also affected by scale deposits. In addition, it restricts achieving the reservoir-monitoring program. Scale Monitoring Program: Fig. 2 Scale Deposits

Two monitoring systems are in place to track the scale deposition and production parameters across the completion / production facilities. a.

Mechanical System

• • • b.

Wireline tubing check for tubing clearance. Choke calibration and NRV inspection/ function test on annual basis. Scale sampling from the strings suspected with scale deposits.

CORROSION MANAGEMENT: This section addresses corrosion management of wells. It is known that corrosion is a major threat to wells. Hence, strenuous efforts are made to contain corrosion in all its ramifications. Emphasis is, therefore, put on corrosion management as a means to assure asset integrity. Corrosion management is divided broadly into corrosion control and corrosion monitoring.

Prediction System (Simulation Model)

Corrosion Control: Zadco has developed Simulation Model (software program) to predict the wells/ strings that might have scaling tendency. Produced water analysis parameters are loaded in the model on monthly basis as well as the wet strings are further updated for mechanical monitoring to confirm the potential of scale deposition. Proactive scale treatment is planned on model prediction results. Scale Prevention & Remedial Process: Frequent wireline gauge cutter / scratchier runs should be made in the strings, producing water or have scale potential, to prevent / remove scale deposits. In case wireline tools fail to remove the scale deposits then following two methods should be used to remove the scaling. a.

Material Selection: Material section for completion string, casing and x-mass tree depends on the reservoir and process operating conditions, the stings are either carbon steel (L-80) or 13% Cr (L-80). After gas breakthrough (GBT) in Upper Zakum the string material may be upgraded. Selection of material for the strings is generally carried out by the aid of software “ZADCORE”, the ZADCO down hole corrosion model. Casing is made of carbon steel (Grade C-75) and x-mass tree material selection is based on API6A. ZADCO’s current x-mass tree grade is EE trim.

Chemical Treatment (Scale thickness 0.5”)

Tubing string with heavy & hard scale deposits are mechanically treated by using Jet Blaster Tool on coiled tubing and pumping down the gelled water and beads mixture to remove and lift the scale deposits.

Corrosion Inhibitor Squeeze Treatment: This treatment is used for the protection of some existing carbon steel production tubing so that life is possibly prolonged till the production string is replaced with 13%Cr. All low potential production wells equipped with carbon steel tubing having no serious scaling and annulus pressure problem, with produced water cut in excess of 2% should be squeeze treated with corrosion inhibitor on regular basis. Wells due for imminent work over are also excluded from squeeze treatment. The quantity of inhibitor to be squeezed should be calculated in accordance with a semi empirical formula which is based on 60 ppm rate over 120 days production. This does may change according to the

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prevailing water cuts or the monitoring results in order to achieve maximum protection period, which is targeted as 4 months per each treatment selection of inhibitor is based on laboratory compatibility testing followed by field trials.

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Downhole Corrosion Coupons: Corrosion coupons are hung inside tubing tail pipes for a standard period of time (usually one month) then retrieved to calculate the tubing corrosion rate. This method is used to achieve the following:

Continuous Inhibition Injection: For gas lift wells, corrosion inhibitor should be continuously injected in the gas lift line at the inlet to the annulus between the string and 9 5/8 casing. The purpose is to provide protection to the carbon steel production tubing and associated WHPT production manifold and subsea oil production lines.

1. Establish the corrosion inhibitor squeeze adequacy according to the prevailing process conditions and water cut. 2. Develop the inhibitor batch volume in order to ensure maximum protection period. 3. Compare the different inhibitor performance hence the selection of cost effective corrosion inhibitor.

Water Injection Treatment:

Analyses of Annulus Fluids:

The injection water is treated for corrosion protection at the water treatment plant for oxygen removal and biocide control.

Samples from high annulus pressure wells are to be collected for compositional analyses for water and oil. These analyses are reviewed in the context of risk and asset integrity.

Annulus Brine Treatment: Wellhead (Surface) Corrosion Coupons: Packer fluid inhibitor contains biocide, corrosion inhibitor and oxygen scavenger. Three of the chemicals shall be compatible (pitting and crevice attacks are potential problems). Oxygen scavenging may be slow & costly. For any stream that will be stagnant such as packer fluid, the total corrosion resulting from the dissolved oxygen is very small and is over as soon as the oxygen is consumed. “The oxygen scavenger needs to be added in pump down. The suppliers of ‘Clear brines’ do not like to do this as it makes the fluid somewhat cloudy. But this reduces corrosion more than anything else.

Corrosion coupons are installed on few wellheads to measure corrosion potential inside tubing, … etc. Similarly, corrosion coupons are also installed in the few water injection headers to measure corrosion in the surface piping. For water injection limits of corrosion coupons are set at 2MPY corrosion rates, in case of high corrosion rate or bacterial activity, measures like pigging and biocide treatment are taken which indirectly reduces the risk of corrosion inside the water injection tubing. Water Injection Monitoring:

WHPT Structure Cathodic Protection: WHPT sub-sea structure is protected with (Al-alloy) sacrificial anodes installed at different parts on the structural members including conductor pipes. However, as per new strategy, 30” conductor pipes exposed to the surface are to be painted prior to installation.

Injection water quality is being monitored at the surface of the injection platform at the rate of 1-2 times per month. This monitoring involves the assessment of Sulphate Reducing Bacteria (SRB) activity either through a water sample or through a biostud at the platform injection header, if available.

CORROSION MONITORING / INSPECTION:

IMPLEMENTATION OF WIMS:

The monitoring methods listed below are being carried out on tubing of the well to ensure the corrosion control measures and practices are adequate. They also provide a feedback on extra measures to be taken to ensure facility integrity.

This implementation involves function/ integrity test of various well components at a defined frequency. This summarized in the table below. The results are needed for decision-making.

Caliper Survey: Multifinger caliper surveys were extensively conducted inside the tubing in the past to produce a model for tubing corrosion. The surveys provided very useful data about tubing metal loss with emphasis in corrosion inhibitor efficiency and effectiveness. It shall be used whenever this is required to establish a particular tubing condition.

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FUNCTION / INTEGRITY TEST

MAINT. / INSP. FREQUENCY 3 months

Corrosion Monitoring (Oil Producers)

Monitor Corrosion in tubing by WL (installation of corrosion coupons). Carryout CI squeeze treatment in the wells that might have corrosion tendency

Sticky Material Monitoring (Gas Injectors)

WL checks to monitor sticky material presence in tubing, DHSV, nipple profile. Collect samples and analyze

3 months

H2/H2S Monitoring

Monitor annuli gas, collect samples and analyze to check for any presence of H2 /H2S gas in the annuli Closely monitor near by producers for gas break through in gas injection area.

6 months

Gas Break Through Monitoring

3 months

ANNULUS INTEGRITY MANAGEMENT: The annulus management is an essential part of the well integrity process during the well operation phase as producer or injector. Frequent testing of annulus pressure shall be carried out in order to pin point those wells, which may need investigation as to the cause of the annulus pressure. Likewise, surface & down hole communication tests shall be carried out on those wells showing high annulus pressures so that rectification or further investigation can be recommended. Annulus integrity assessment process is shown in Fig. 3.

Fig. 3 Annulus Integrity Assessment Process RISK MANAGEMENT: The risk management plays a crucial and integral role during WIMS implementation. Risk based technique is mandatory for effective well integrity management. Risk elimination activity should focus on most critical work and integrity / barriers. It is intended that all aspects of will be conducted to maintain a level of risk As Low As Reasonably Possible (ALARP). Under specified operating conditions, there is no intolerable risk of failure endangering the safety of personnel, environment or asset value. Once hazards are identified along with effects, a qualification and evaluation of the effects have to be carried out mainly their exposure to personnel, well, process and environment. Risk assessment process shall follow the ADNOC ‘Risk Potential Matrix Qualitative’ criterion (Fig. 4).

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Risk Potential Matrix Qualitative PROBABILITY A

Severity

People

Assets

Environment

Reputation

5. Catastrophic

Mulitiple fatalities or permanent total

Extensive damage > 10 Million

Massive effect

International impact

4. Severe

Single fatality or permanent total disability

Major Damage < 10 Million

Major effect

National impact

3. Critical

Major injury or health effects

Local Damage ~ 0.5 Million

2. Marginal

Minor injury or health effects

Minor Damage ~ 0.10 Million

Minor effect

Minor impact

1. Negligible

Slight injury or health effects

Slight Damage