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Document of
The World Bank
FOR OFFICIAL USE ONLY
Report No. 7916
PROJECT COMPLETION REPORT
TURKEY
OIL RECOVERY ENGINEERING PROJECT(LOAN S-13-TU)
AND
BATI RAMAN ENHANCED OIL RECOVERY FIELD DEMONSTRATION PROJECT(LOAN 1917-TU)
JUNE 26, 1989
Energy Operations DivisionCountry Department IEurope, Middle East and North Africa Regional Office
This document has a restricted distribution and ma, be used bv recipients oniv in the pertormance oftheir official duties. Its contents may not otherwise be disclosed without World Bank authorization.
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TH WORLD SANK FOR OMCIAL USE ONLYWashington. DC 20433
USA
O.e W D<tVwISMiMb
June 26. 1989
MEMORANDUM TO THE EXECUTIVE DIRECTORS AND THE PRESIDENT
SUBJECT: Project Completion Report on TurkeyOil Recovery Engineering Project (Loan S-13-TU) andBati Raman Enhanced Oil Recovery Field DemonstrationProject (Loan 1917-TU)
Attached, for information, is a copy of a report entitled 'ProjectCompletion Report on Turkey - Oil Recovery Engineering Project (Loan S-13-TU)and Bati Raman Enhanced Oil Recovery Field Demonstration Project (Loan 1917-TU)' prepared by the Europe. Middle East and North Africa Regional Office withPart II of the report contributed by the Borrower. No audit of this projecthas been made by the Operations Evaluation Department.
Attachment
This document has a restricted distribution and may be used by recipients only in the performanceof their official duties. Its contents may not otherwise be disclosed without World Bank authonization.
FOR OFmFCIAL USE ONLY
PROJECT COMPLETION REPORT
TURKEY
OIL RECOVERY ENGINEERING PROJECT (LOAN S-13-TU)and
BATI RAMAN ENHANCED OIL RECOVERY FIELD DEMONSTRATION PROJECT (LOAN 1917-TU)
TABLE OF CONTENTS
Page No.
PREFACE ....................................................... iEVALUATION SUMKARY ............................................ ii
PART I-
Project Identity ......................................... 1Background ............................................... 1
3. Pro,ect Objectives and Description ....................... 24. Project Organization and Implementation .................. 35. Project Results ............................... ........... 66. Project Sustainability ................................... 77. Bank Performance ......................................... 78. Consulting Services ...................................... 89. Performance of the Beneficiary (TPAO) .................... 9
PART II
Comments from the Borrower on Part I ..................... 11
PROJECT COMPLETION REPORT
I. INTRODUCTION ............................................. 17
II. PROJECT IDENTIFICATION, PREPARATION ND APPRAISAL ........ 18Origin of the Project ..... ..... ................... 18Preparation and Appraisal ........................... 19Project Description ................................. 21
III. PROJECT IMPLEMENTATION ................. .... ......... 223.1 The Bati Raman Field Carbon Dioxide Injection Project 22
Project Management .................................. 22Project Ccst ........................................ 22Project Disbursement ................................ 23Procurement and Construction ........................ 24Surface Facilities .................................. 25Dodan Plant ......................................... 25
This document has a restricted distribution and may be used by recipients only in the performanceof their official duties. Its contents may not otherwise be disclosed without World Bank authorization.
TABLZ OF CONTENTS (Cont.)
Page No.
The Dodan-Bati Raman Pipeline ....................... 29Bati Raman Field .................................... 29Project Planning .................................... 30Well Design ......................................... 33Project Execution .......................... ..... 34Performance Analysis ................................ 43Project Expansion ................................... 46Conclusions ......................................... 48
3.2 The Raman Field Development Project .... ............. 503.3 The Hamitabat Gas Field Stimulation Project .. ..... 563.4 The Management Study ... I ............................ 58
ANNEXES
1. Categories of the Appraisals for the ."roceeds ofLoan 1917-TU .................... 61
2. Categories of the Project Disbursement of Loan l917-TU 623. Procurement Schedule of Orders and Deliveries of Main
Items of Equipment for Loan 1917-TU ................... 63
FIGURES
1. The Bati Raman Field EOR Pilot Project Application ...... 682. Sir.mplified Flow Diagram of the Pilot Project .... ........ 69i. Bati Raman - CO2 Project ....... ......................... 704. Production History About Regions ........................ 715. Production & Injection History of the Fieldi .... ......... 726. Oil Production .......................................... 737. Monthly Oil Production (MSTB) ........................... 748. Bati Raman - CO2 Injection Efficiency .759. Injection History of Well 1109 .......................... 7610. Production History of Well 1182 ......................... 7711. Status of B. Raman Western Area Wells ................... 7812. Produced Oil Distribution of B. Raman Western Area Wells 7913. Pressure Distribution of B. Raman Western Area Wells .... 8014. GOR Distribution of B. Raman Western Area Wells ......... 8115. Production Time in "Huff & Puff' Pnplication ............ 8216. Gas Flooding Performance of Prodo tion Wells ............ 8317. Gas Solubility i.l Oil in Matrixes and Fractures ......... 8418. The Gas Flooding Performance of Wells with
Low Injection Rates ................. . .................. 8519. The Bati Raman Field EOR Project Expansion ........ ..... 8620. Cumulative Water/Cumulative Oil (MSTB) .... .............. 87
TABLE OF CONTENTS (Cont.)
Page No.
PART III
1. Related Bank Loans ....................................... 882. Project Timetable ........................................ 893. Loan Disbursements ....................................... 904. Project's Objectives and Description ..................... 905. Project Costs and Financing .............................. 916. Project Results .......................................... 937. Status of Covenants ...................................... 968. Use of Bank Resources .................................... 99
GRAPHIC
Bati Raman EOR Project - Planned and Actual Disbursements 101
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TURKEY
OIL RECOVERY ENGINEERING PROJECT (LOAN S-13-TU)
AND
BATI RAMAN ENHANCED OIL RECOVERY FIELD DEMONSTRATION PROJECT (LOAN 1917-TU)
PROJECT COMPLETION REPORT
PREFACE
This is the Project Completion Report (PCR) for the Oil RecoveryEngineering Project (Loan S-13-TU) and the Bati Raman Enhanced Oil RecoveryField Demonstration in Turkey, for which Loans S-13-TU and 1917-TU in theamounts of US$2.5 million and US$55.2 million, respectively, were approved onNovember 30, 1978 (Loan S-13-TU), and on November 24, 1980 (Loan 1917-TU).The lu,ans were closed on December 31, 1987. Loan 1917-TU was not fullydisbursed and the last disbursement was on July 18, 1988.
The PCR was jointly prepared by the Energy Operations Division,,..ountry Department I of the Europe, Middle East and North Africa RegionalOffice (Preface, Evaluation Summary, Parts I and III) and the Borrower, (Partii).
Preparation of this PCR is based, inter alia, on the Staff AppraisalReport; the Loan, Guarantee, and Project Agreements; supervision reports;correspondence between the Bank and the Borrower; and internal Bank memoranda.
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PROJECT COMPLETION REPORTTURKEY
OIL RECOVERY ENGINEERING LOAN(S-13-TU)
ANDBATI RAMAN ZNHANCED OIL RECOVERY FIELD DEMONSTRATION PROJECT
(LOAN 1917-TiJ)
EVALUATION SUMMARY
Introduction
1. The project was the second Bank operation in Turkey's petroleumsubsector and the first Bank financed project anywhere to utilize enhLanced oilrecovery (EOR) technology to increase oil production. A study financed undera preceding engineering loan (S-13-TU) for US$2.5 million had recommendedcarbon dioxide (C02) injection into the oil reservoir and this project wasdesigned as a follow up pilot project (PCR, Part I, paras. 2.02-2.03). TheBank loan of US$62.0 million, approved on November 18, 1980, was given toTurkiye Petrolleri A.0. (TPAO), the national oil company, with the guaranteeof the Republic of Turkey.
Obiectives
2. The main objectives of the project were to expand Turkey'srecoverable reserve base through: (a) application of EOR technology at BatiRaman; (b) development of the newly discovered oil reserves in the Raman oilfield; and (c) reserve evaluation and stimulation of gas wells in theHamitabat field to increase deliverability.
ImDlementation ExDerience
3. Although delayed by three years due mainly to technic I andprocurement problems, as well as change in scope of EOR method, '- projectwas completed with savings of US$24 million (23.4%) in total proje.. -b-s.The savings can be attributed in part to prudent use of local contractors forthe civil works portion as well as to the devaluation of the Turkish Lirevis-a-vis the US dollar (PCR, Part III, Section 4). The disbursement of theloan was slower than forecast reflecting implementation delays experienced byTPAO (PCR, Part I, para 4.02(a) and para 9.01). The unutilized portion of theloan (US$7.4 million) was cancelled retroactively to March 18, 1988. Theperformance of the consultants and contractors was rather uneven, particularlyin the early stages of the EOR component when TPAO apparently did not closelysupervise its consultant. This situation improved in the course ofimplementation, when adequate coordinating arrangements were put in place toensure satisfactory performance (PCR, Part I, para 8.01). The Bank'ssupervision was satisfartory and a reasonable continuity of staff working onthe project was maintained throughout implementation.
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Biua
4. While the EOR method initially identified as having the most promise('huff n puff' method) was changed to gas line drive, the physical objectiveswere saiccessfully met. Oil production from Bati Raman heavy oil fieldincreased from 900 barrels per day (B/D) to 6,600 B/D by 1989 (PCR, Part ',para 5.01). Gas deliverability from the Hamitabat aas field was increasedfcurfold from 15 million cu.ft. per day to 60 million cu.ft. per day in 1989as a result of the well stimulation program. For the Raman field, TPAO wasable to recommence oii production whereby the net yearly oil production is nowover 200,000 barrels.
Sustainabilitv
5. TPAO's oil production from Bati Raman is expected to almost double by1990 as the positive results of the pilot test project are being soplied toother areas of the field. The C02 injection EOR process would continue toyield net economic benefits at an acceptable level even in a lowerinternational crude price scenario.
Findings and Lessor.E
6. The rather long delay in conpleting the project components has beenattributed to various factors including changes in project design necessitatedby new developments during implem,ntation (PCR, Part I, para 9.01); however, asalient lesson of the project experience points to the need for ensuring thatall tasks, whether to be performed by the implementing agency, contractors orconaultants are coordinated and strictly monitored if unexpected delays are tobe minimized.
Part I
1. Pro1ect Identity
Project Name: Bati Raman Enhanced Oil Recovery Field Demonstration ProjectLoan No: 19i7-TURVP Unit: Europe, Middle East and North Africa RegionCountry: TurkeySector: EnergySubsector: Petroleum
2. Background
2.01 The project had its genesis In the heavy burden Turkey's oil importsplaced on its balance of payments. The rapid industrial -'xpansion of theTurkish economy since the mid 1970s and the slowly declining domestic oilproduction resulted in an increased dependrtce on imported oil and petroleumproducts. While petroleum imports absorbed 60% of merchandise export earningsin 1978, they absorbed all of the merchandise earnings in 1979 and wereexpected to surpass the merchandise earnings in 1980. In this situation, theenergy policy of the Government of Turkey (GOT) focused on restraining oilimports by developing indigenous energy resources such as coal, lignite andhydropower, by implementing measures to improve the efticiency of energy useand by augmenting indigenous oil and gas production.
2.02 The Petroleum Exploration Project, covered by Loan 1916-TU (approvedand signed on the same dates as the subject Project), was completed by he endof 1985, i.e. about two years earlier than the subject Project. The PCR onthat Project has concluded that the Project was a qualified success, inasmuchas it strengthened TPAO as an institution and added about 14 million barrelsof oil to TPAO's established recoverable reserves, although the explorationeffort was not a commercial success. Under the Project, TPAO's oil importingand refinery activities were separated from its exploration activities on theargument that TPAO's financial resources should be linked to the success ofits exploration program. However, the outcome of the restructuring has beendifferent from that originally envisaged at appraisal, and the dividends fromTPAO's refineries and marketing subsidiaries are now financing TPAO'sexploration effort because of the fall in crude oil prices and GOT's pricingstrategy for petroleum products.
2.03 In early 1978, TPAO requested Bank assistance in developing a programto increase the ultimate recovery of the Bati Raman oil field, the largest oilfield in Turkey, but producing heavy oil, through the use of enhanced oilrecovery (EOR) technology. U3ing financing provided by an engineering loan(S-13-TU) of 1978 for $2.5 million, a group of consultants undertook acomparative evaluation of alternative EOR technologies applicable to heavy oilto determine the optimal enhanced recover-, method. This study indicated thatcarbon dioxide (C02) injectioji into the oil reservoir should be therecommended EOR method, a conclusion that confirmed the results of TPAO's ownstudies and was further confirmed by two other independent consultants. TheBati Raman Component (Loan 1917-TU) was thus a pilot project to test a systembased on the conclusions of the engineering loan. Since the engineering loanwas refinanced under the subject loan, this PCR should be considered asapplicable to both the engineering loan and Ln 1917-TU.
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2.04 During the final stage of the EOR study financed under theengineering loan, GOT also requested Bank assistance for: (a) the developmentof the newly discovered extension of the established Raman oil field; and(b) the assessment of the production potential of the Hamitabat gas field inThrace in northwestern Turkey.
2.05 Part II of the PCR, prepared by TPAO, although a good reportassessing the problems faced in implementation from a technical perspective,has serious limitations in addressing key implementation issues such asprocurement, performance of consultants, contractors, the Bank and TPAO, andan assessm'ent of the Project results vis-a-vis appraisal expectations.
3. ProAect's Objectives and Description
3.01 The project has three main objectives: (a) to increase Turkey'scrude oil production in the short term by developing the newly discovered oilreserves in the Raman oil field; (b) to expand Turkey's recoverable reservesbase through the application of new euihanced oil recovery techniques and toenhance its medium-term petroleum production capacity; and (c) to evaluate thegas reserves and production potential of a newly discovered gas field.
3.02 The project comprised the following four components:
(a) The Bati Faman Field Test - Following completion of thecomparative evaluation study, which recommended the applicationof CO2 technology, it was proposed to undertake ademonstration test to determine whether the process would infact produce the expected results. If successful, the resultsof this two-year demonstration test would provide TPAO with thebasic operating data required for it to design an efficient fullfield development project. The field demonstration test of thechosen carbon dioxide EOR technology would be carried out on 10percent of the reservoir. It would require the drilling of fivewells at the Dodan gas field to produce carbon dioxide gas, theremoval of sulphur fron the gas, the laying of a 75 km pipelineto transport 55 million cubic feet per day of carbon dioxide gasfrom the Dodan gas field to the Bati Raman oil field at apressure of 2000 psi, the drilling of an additional 5 wells inBati Raman, the preparation of a total 30 wells to handle C02injection and oil production, and the installation of associatedequipment in Dodan and Bati Raman. Workover rigs, a cementingtruck, specialized laboratory equipment, and equipment andseIeices comprising technical assistance for testing, monitoringand evaluating the results, were also included;
(b) The Raman Field Development - This component would assist in theexpansion of production from tne newly discovered northernextension of the Raman oil field, through the drilling andcompletion of 18 new production wells and the installation ofassociated surface and subsurface equipment. In addition,technical assistance for a reservoir study was proposed in orderto determine the optimum approach to a secondary recoveryprogram for the entire field;
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( ) Thrace (HAmitabat) GaR Fleld - The production potential of theHamitabat gas field would be evaluated by fracturing and testingsix to ten wells to provide reliable estimates of gas reservesand field productivity and to determine the optimum utilizationof its gas. Although seven wells had been drilled and thre'were already producing a total of five million cu.ft. per day ofgas, neither tht reserve estimates nor the production fc ecastslent sufficient confidence to permit the implemeitation ofprojects designed to consume the gas over an extended period oftime. Technical assistance for a atudy of gas reserves andoptimum utilization of the gas was also included; and
(d) Technical Assistance - To strengthen TPAO's management andorganization, TPAO would be provided with specialized assistancefor improving its operational productivity aiid its managementorganization. At appraisal, TPAO was running a huge operationwith little of the work contracted out. The organizationalstructure, systems of internal communication, control ofoperations, warehousing, accounting and financial management,financial planning systems and managemtilt of its subsidiarieswould be carefully reviewed with a view to improving TPAO'sperformance within set policy objectives.
4. Prolect Organization and Implementation
4.01 Proiect Organization. Since the Bati Raman Field Demonstration Testwas an inherently risky project, work on the project had to proceedcautiously. Accordingly, the following steps were taken to ensure the successof this and the other project components:
(a) TPAO would create, for each project component, a special projectimplementation group with qualified and experienced staff. Theorganization and ctaffing of the groups, their technicalresponsibilities and financial authoricy were agreed upon withthe Bank before project implementation. The effectiveness ofthe groups and their staffing were to be constantly reviewedduring project implementation and if the capabilities of thesegroups fell below acceptable levels by the loss of qualifiedtechnical personnel, TPAO agreed to secure adequate outsidetechnical assistance;
(b) Although TPAO had overall responsibility for projectimplementation, it would call upon foreign expertise in areaswhere it lacked technical capabilities. Accordingly, for theBati Raman EOR Field Demonstration Test, it engaged separate,experienced consultants for detailed engineering design, forsupervision and start-up and for monitoring and evaluating thefield tests. For the Raman field, TPAO would engage consultantsto carry out a reservoir study to help determine the optimal EORprogram for the field. For the Thrace gas field, TPAO wouldengage specialized service companies for fracturing and testingof the gas wells to help evaluate the production potential andto provide reliable estimates of its gas reserves. TPAO wouldalso engage consultants to undertake a study of the technicallyand economically optimuri utilization of tne gas reserves, once
the gas field's production potential was established. Welllogging operations for the Raman, Jodan and Hamitabat fields andfor exploration wells would be provided I/ by a competentforeiSn contractor;
(c) As the carbon dioxide injection enhanced recovery method wasbeing applied to heavy oil for the firs* time under theconditions obtaining at Bati Raman, TPAO was required toimplement this subproject in stages. TPAO was required tosubmit a phased implementatio2 program before October 1981 forthe Bank's approval, to ensure that each phase wassatisfactorily implemented and its progress r viewed before workwas exteD4ed to the entire 30-well program of the subproJect.Furthermore, TPAO alao agreed not to undertake field tests ofthe C02 injection in the central section of the reservoiruntil the Bank and TPAO agreed that the results of the testsjustified extending the tests to the central section; and
(d) To benefit from the experience of foreign companies andagencies, TPAO agreed to establish by October 1, 1981 onadvisory panel (independent of its consultants) consistivg of atleast three experts experienced in heavy oil recovery or C02injection to review the progress of the tests and resolveunforeseen problems.
4.02 Implementation. The details of implementation of the various projectcomponents are given below:
ka) Bati Raman EOR Field Demonstration Test. This component wascompleted over three years behind schedule due to slippages thatcould be attributed to staff shortages, delays in procurementand in the inadequate performance of consultants andcontractors. The detailed reasons for the delay were as follows:
(i) Decreasing real staff salaries caused serious staff moraleprobiems in 1980 and 1981 and a large exodus of technicaland managerial staff. The shortage of technical personneland changes in the production group management adverselyaffected project implementation; r
(ii) The poor performance at least initially of the expatriateconsultant charged with the design, procurement andsupervision of the project and the sluggish performance ofthe Turkish consultant entrusted with the design work forcivil construction;
1/ Para 4.01(b) - Although this was the understanding of the appraisalmission, it was not explicitly stated in the Project kgreement (seeSAR, para. 5.23).
(iii) Delays in the procurement of equipment and services due tothe large number of contracts (over 400) that had to bereviewed and cleared by the Bank as well as theinexperience and lack of familiarity of TPAO staff with theBank's procurement procedures. This caused delays allaround in implementation of various components such asdrilling and work over of Bati Raman and Dodan wells,construction of surface facilities, construction of gaspipeline from Dodan _o Bati Raman, etc.;
(iv) Poor coordination by TPAO of the work of the variousentities involved in project implementation such as theconsultants and contractors, resulting in delays indecision-making and contract awardsl';
(v) Faulty design of the unloading valve and instrumentation ofthe C02 compressors and of the pumping unit for theSelexol plant leading to a four-year delay in commencingthe C02 EOR pilot test;
(vi) Change in the design of C02 gas injection method from'huff n puff' to gas line drive in view of the discouragingpreliminary results and the occurrence of C02 break-through in several wells which was not foreseen in theconsultants' design; and
(vii) Delay in the installation of surface facilities by Turkishcontractors at the Dodan plant
Ultimately, C02 injection in the project area cummenced in March1986. However, certain technical problems such as the unsatisfactoryfunctioning of the control panels of the compressors arose and the plant wasshut down on May 1, 1986. The problems were corrected and steady C02injection at 15-20 million cft. per day started in September 1986. Corrosioninhibitor has been injected in che wells and TPAO is monitoring possiblecorrosion in C02 wells as well as in surface facilities on a regular basis.One continuing problem is the excessive Selexol consumption in the C02processing plant (over six times the designed consumption) which is raisingoperating costs. Efforts are under way to resolve this problem. In theinterim, TPAO has procured C02 conservation facilities such as recyclingcompressors to reinject th.' C02 produced with the oil at Bati Raman.
l/ Para 4.02 (a)(iv) TPAO disputes this point and claims that it hasalv.~,ys had a good coordination with consultants and contractors.This paragraph reflects the view of the Bank staff.
(b) Raman Field DeveloDment. This component has been satisfactorilycompleted but is over two years late. Initially, the componentwas commenced using TPAO's own materials but the stock wasreplenished when the Bank-financed materials began arriving atTPAO's stores. In mid-1986, about two years later than theappraisal estimate, the expatriate engineering consultants havesubmitted satisfactory reservoir studies on the Raman field, aswell as the nearby Garzan field, which was added to the projectscope. Based on the consultant's recommenaations, infill wellshave been drilled and additional d-ta is being collected priorto undertaking a pilot water flood at the Raman field;
(c) Hamitabat Gas Fleld. Fracturing operations, expanded from theoriginal six to twenty-four wells, were conducted with the helpof a renowned expatriate firm. These were completed ! November1984 and have been very successful. Well productivit. increasedfive-fold as a result of fracturing;
(d) Management Studv. The study, conducted by an expatriate firm ofconsultants, was completed in April 1987. TPAO has reviewed thestudy and is implementing some of the recommendations; inparticular, TPAO is taking steps to insta'll an MIS system.TPAO's staff have undergone training with the consultants toenable them to efficiently run the MIS operations.
5. ProJect Results
5.01 Except for a reduction in the number of wells in the Raman componentfrom 18 co 17 and an increase in the stimulatiLn program in the Hamitabat gasfield from 6 to 24 wells, the Project was comoleted as planned at appraisal,though over three years late. It also substantially achieved its physicalobjectives. The Project demonstrated che successful application of the C02gas injection EOR technology in the pilot area. T'e 'huff n puff' methodinitially recommended by the consultants did not pruve effective, but thechange to the gas line drive method yielded positive results. The total oilproduction in the pilot area and in the surrounding area, which was affectedby the CO2 injection, increased from 300 B/D before the start of the C02injection to 5,600 B/D (April 1989). Overall, the oil production in theentire Bati Raman field increased from 900 B/D just prior to the C02injection to 6,600 B/D (April 1989), 90% of this increase being attributableto the EOR technology applied. In view of the successful outcome of theProject, TPAO is planning a cautious C02 injection program to increaseproduction to 10,000 B/D by 1990, an output achievable without major capitalinvestments.
5.02 Raman and Garzan Fields. The reservoir studies for the Raman andGarzan fields have been satisfactorily completed. They have evaluated thereservoir potential and made recommendations for increasing production.Practical results will follow from implementation of the recommended pilottests, which are expected to comrmence ir 1989, and the development strategybased on the experience gained by TPAO.
5.03 Hamitabat Gas Flield. TPAO expanded trie stimulation program for theirwells and has improved gas proiuctivity from the tight sands. Prior to thewell stimulation program (hydraulic fracturing), the Hamitabat field wasproducing about 15 million cu.ft. per day. As a result of the reservoirfracturing operations financed under the project, the Hamitabat gas fieldproduction has been ir.creased about fourfold to 60 million cu.ft. (April 1919)per day. However, currently, the field is producing at only half its capacitydue to the fact that the nearby Ambarli Power Plant, has been temporarii)shifted to Russian gas, secured under a take-or-pay arrangement because of theabsence of infrastructure for the transmission and distribution of gas toother consumers. This situation will change when, the development of theIstalOul gas distribution network and other similar dis.tribution networks iscompleted, at which time the Russian gas will mostly be absorbed and theAmbarli Plant switched back to Hamitabat gas.
5.04 Management Study. The stuldy, conducted by expatriate and Turkishconsultants, identified various areas for improving the organization andmanagement of TPAO. Steps to implement a plan , install an MIS system inTPAO are under way.
6. Proiect Sustainability
6.01 TPAO has been able to complete the project with cost savings of about23% compared to the appraisal estimates, despite the change in project scopeand protracted implementation delays. In spite of the initial setback withthe cyclIc C02 gas injection (huff and puff) process envisaged at appraisal,TPAO managed to alter the C02 gas injection to line drive with significantsuccess. At the current level of production of about 6,600 bbl/day (2.4million barrels/year), exiEcted to increase to 10,000 bbl/day (over 3.5million bbl/year) without significant capital investment in C02 injectionfacilities, the Project is economically profitable and well sustainable in thefuture. The net benefits would continue at the present acceptable level,except in the event of a collapse of oil prices.
6.02 TPAO is currently producing Bati Raman crude at a proe ztion cost ofabout US$4/bbl. With the conservation of the C02 produced with oil, andrecycling it into the Bati Raman reservoir and increasing field productior. to10,000 bbl/day by 1990, the production costs are expected to be furtherreduced by about 20%. It is, therefore, considered that the C02 EOR processat Bati Raman would continue to yield net economic benefits at an acceptablelevel even in a lower international crude price scenario, and would contributetoward improving the balance of payment problems facing the country.
7. Bank Performance
7.01 The Bank performed well under the Project. It proceeded with cautionin handling a technology that had not been proven in the conditions obtainingin Bati Raman. It counselled TPAO appropriately as problems arose in thecourse of project implementation and while doing so, it maintained goodrelations with GOT and TPAO. For example, in December 1984, when theproduction had sharply declined to 250 barrels/day, the Bank advised TPAO torun a complete reservoir pressure survey in the pilot area and to do someformation logging as the data would provide useful inputs in later C02 pilotmonitoring and modelling. The Bank further advised TPAO to seek assistancefrom international oil companies at the critical time of supervision of theCO2 injection and monitoring of reservoir behavior. In the case of the gaswells at Hamitabat, the Bank suggested that long duration
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isochronal tests in some key wells be carried out since TPAO had only testedthe wellc for very short periods. All these suggestions were accepted byTPAO. Close liaison by Bank staff with TPAO ted the consultants in reservoirperformance helped TPAO in making timely changes in project execution. Aparticularly useful contribution was made by Bank staff in their discussionson critical occasions with TPAO, the consultants and suppliers (e.g. of C02compressors), when a near stalemate among them threatened serious delays inproject execution.
7.02 Perhaps in two areas, the Bank's performance might have been better.Knowing that this was among the Bank's earliest involvements in the petroleumsubsector and that TPAO had no experience of the Bank's procurementprocedures, greater attention could have been paid to educating TPAO's staffin these procedures and to better packaging of the goods and services procuredunder the Project. The Bank could also have conducted a more rigorousscrutiny of TPAO's contracts to ensure a tighter control of the performance ofconsultants and contractors. The Bank's review and questioning did result inbetter terms for TPAO in the consultants' contract in the Bati Raman component.
7.03 With regard to supervision too, the Bank's performance was verysatisfactory. The Project was supervised at regular intervals except for thelast one in December 1987, which was mounted 17 months after the previous onein July 1986, arising from some staff discontinuity during thereorganization. Otherwise, there was also reasonabl' continuity of Bank staffworking on the Pro2ect.
8. Consulting Services
8.01 From mid-1981, TPAO engaged an expatriate firm (later assisted by aTurkish firm) as consultants to help in detailed engineering design, materialsprocurement, on-site supervision of surface facilities and monitoring of theCO2 pilot test. The performance of the consultants was rather uneven. Forexample, there were frequent changes in the design of the portable heaters,one of the Selexol towers and the gas separators as correctly alleged by theTurkish fabricator. In the early stages, there was inadequate follow-lip ofprocurement to ensure that suppliers met specifications on some equipment.There was also some excessivre billing and overcharging for the engineeringservices which were raised with the firm at the insistence of the Bank. Theexcessive billing was finally corrected and it was agreed as a correctivemeasure that TPAO would obtain from the consultant monthly budgets of manhoursand jobs in full detail. For all these reasons, the Bank did consider theconsultant's performance in 1983 as unsatisfactory. Ir 1984, their contractwas renewed as TPAO was reluctant to have a change at that stage. With bettersupervision by TPAO and the active intervention of the Bank at criticalstages, the consultant's performance improved in due course and could beconsidered satisfactory.
8.02 The performance of other consultants such as those under the Ramanand Garzan component and the expatriate ,irm of management consultants was,generally speaking, satisfactory.
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9. Performance of the Beneficiary (TPAO)
9.01 The Project was delayed by over three year. mainly because ofstaffing problems, r:ocurement delays, and the unsatisfactory perfcrmance ofconsultants and contractors. The delay was also partly due to changes inproject design necessitated by new developments during implementation. Thedelay, for which TPAO was to some extent responsible, could have been largelyavoided with proper coordination of all tasks and a strict monitoring andenforcement of contractual performance both by contractors andconsultants.l/ Part of the delay in procurement was no doubt due to TPAO'sunfamiliarity with the Bank's procurement procedures, but it was also partlydue to TPAO's own internal problems. At the same time, TPAO deserves creditfor successfully completing all the components of the project and for itsresponsiveness to reasonable suggestions by the Bank.
1/ TPAO does not accept the view that the change in injection patterncontributed significantly to project delays. Again this representsthe opinion of t'ie Bank staff.
- 10 -
PART II
(PCR PREPARED BY TPAO)
AND
COMMENTS FROM THE BORROWER ON PART I
- 11 -
COMMENTS FROM THE BORR(CER 'N 'AP: T Page 1 of 5U _ _ _ _ ___
e -
! hal i Pt I P | I i rt 4 I, %It1il 111
. -. .... .e eee -A.. .. d 2 P -
,s'.i-* r' ~~~~~* -r, M-
*2 42 .. . .
t ; ~~'ar T8*...
- 12 -Page 2 of 5
of foreign companies particularly at Middle East area, however
this has not affected the implementation of the Bati Raman
project. Because, the project has been conducted almost by the
same managerial staff from the beginning up today.
The poor performance of the Item 4.02 la) (iii):
expatriate consultant alreadvmentioned. No need to amend Although the lack of familiarity of TPA0 staff with the
Part I. Bank's regulations might have contributed to delays in the
procurement and construction phases of the project, the main
reason is attributable to slow processing in initial review
of RFQ ducuments, evaluation reports and subsequent contract
documents, and the concurrance of Letter of Credits by the World
Bank.
Another fact caused a del.ay in the proJect implementation
has occurred as follows. During the time elapsed between the
finc.Iization of S-13 T" and the date Loan 1917 TU became
effective, the expatriate consultant temporarily suspended their
engir.eering activities due to unpaid invoices which also
res.uted s'hut 6-month delay in the mnplementatiorn of the project.
These comments given as a Itern 4.0. (a) (i;):
footnote under para 4.02 (a) (IV)
PA' al'wa.s F.ave had a qw2:d ^.-r Inatian Wi .nunsultants
and :-ntractors whic-. we Lon t oe.len'e r,s -:i ad., lay .n
lecision-making nd czrntract awarls dar; the ;rr..ect
irmple-entation. in c.rar , T ' s feref -
by means of this ccnri:nato:n a4ain.a :.r :ed iemanrs
-aricas entities :.y-::ei_ ; te
The Bank disagrees as the change t 4.; a) a.in gas injection did resultin implemeatation delays. .anqe in t-. gas ln'ecrt-o-n :oar-n fr:n !.nf- anrd pff
to qjas lIne drIve os n at s eas n a uais.- idoIa; sn the prcect
impleme-.tatl:.n, r.t a cor.se-. enoe -f - t-: .;eld oi1 ot an,loed in
the pro,ect area. Infact, T'A's ale:r..ss on the onteruretation
of field results and de-ision mn cn.'ern : t,o ,as 'line drove
has resulted in today's success-.l ';eli aopulLcation.
- 13 -Page 3 of 5
Para 4.02 (a)(VIII) has been Item 4.02 (a) (viii)deleted.
Since it is related with the Hamitabat gas field, it
should be omitted from the section related with the Bati
Raman field.
Para 5.01 has been suitably Item 5.01:amended,
Starting from 6th ltne, this paragraph may be revized
as follows consisting of latest production figures:
'The "huff and puff' method initially recommended by
the consultants did not prove effective, however field results
showed that most of the production increase was due to the
gas drive mechanism in the reservoir and therefore the
injection pattern was changed from "huff and puff" to gas
line drive which yielded positive results. The total oil
production in the pilot and surrounding area (CO2 affective
area) increased from 300 B/D before start of the CO2injection to 5600 B/O in April 1989. Overall, the oil
production in the entire Bati Raman field increased over
6600 B/I in April 1989 whereas it was estimated to be around
900 B/D on primary production, 90 % of this increase being
attributable to the EOR technology applied. In view of the
successfull outcome of the Project, TPAO is planning a
cautious CO2 injection program to increase production to
10 000 B/D by 1990, an output achievable without major oapital
investments.'
Para 5.03 has been amended. Item 5.03
Prior to well stimulation program (hydraulic fracturing),
the Hamitabat fieid was producing about 15 million cu.ft.,day.
As a result of the fracturing operations financed under the
pro;ect, the Hamitabat gas field production has been
increased about 4 fold to 60 million cu.ft.!day.
. / . .~~~~~~
- 14 -
Page 4 of 5
Para 6.01 has been amended. Item 6.01:
%he current level of Bat. Raman field production of
about 6600 B/D may be ins. rted into this paragraph.
Para 6.02 has been amended. Item 6.02:
In our records, the operating cost of currently
producing Bati Raman crude is about 4 USD/Bbl.
Para 7.01 has been suitably Item 7.01:amended. The production of Dati Raman field had never declined to
250 8/D in his history which can be seen in Figure 6 of Part II.
The production in the pilot area was about this range due to the
low reservoir pressure before start of the gas injection.
No change needed in Part I Reservoir pressure sarvey has been carried out in the field
of the FCR. as a routine operation since the beginning of the field production.
Formation logging has also been applied to all Bati Raman wells
as a usual procedure in order to provide useful data for the
evaluation and better understanding the reservoir conditions.
No change needed in Part I The reliability of deliverability tests does not depend
of the PCR. on the isochronal time selected, but the extended flow time is
important. This fact has been considered by TPAO in carrying out
the deliverability tests in Hamitabat wells, and the extended
flow periods were long enough to reach tle semi-steady state
conditions.
These comments given as a Item 9.01:footnote under Para 9.01.
As mentioned above (Item 4.02 a-vi) changes in the
injection pattern cannot be considered contributory to delays.
Also, our other comments on delays must be taken into account
for this paragraph.
.1/. .
- 15 -
Page 5 of 5
For Part III of the Project Completion Report, we
agree with the text and do not have ary comment on that.
Ai,o, please note that TPAO's Project Completion
Report dated November 1, 1988 can be used as Part II of the
final PCR.
We hope our above comments will be helpfull in the
revision of your final report.
Sincerely Yours,
TURKISH PETROLEUM CORPORATION
'"~~ t^-rAlk
OK/CS
18.5.1989
v 'UZA..
- 16 -
TURKEY
PROJECT COMPLETION REPORT
THE BATI RAMAN ENHANCED OIL RECOVERY
FIELD DEMOiNSTRATION PROJECT
(LOAN 1917-.JU)
Turkish Petroleum Corporation Production Department
- 17 -
TURKEY
PROJECT COMPLETION REPORT
THE BATI RAMAN ENHANCED OIL RECOVERY
FIELD DEMONSTRATION PROJECT
(LOAN 1917 - TU)
I. INTRODUCTION
1.01 Like many countries in the world, petroleum supply
has become a focal point of the economic pioblems that
Turkey faces today. The share of crude oil in Turkey's
overall energy requirements has increased sharply over
the last two decades from 20 percent in 1960 to 45 percent
in 1986. Although Turkey was producing approximately
3 million tons of crude oil per year, the rapid industrial
expansion of the economy since the mid-1970s resulted
in an increased dependence on imported oil and its products.
Domestic oil production, which declined slowly through
most of the 1970s, currently accounts for about 14 percent
of Turkey's overall oil requirements of about 16 million
tons.
1.02 The Government of Turkey (GOT) has made concerted
effords to reduce the growth of oil consumption by replacing
it with lignite and hydropower for electricity generation,
and with coal for process heat in industries. While
these efforts have helped to stem the growth of oil
consumption, the potential for additional petroleum-
substitution projects was limited. Therefore, a new
strategy was needed to be established on Turkey's overall
energy requirements. The efforts to augment domestic
pe.roleum production through the introduction of enhanced
oil recovery (EOR) technology for older and most,y heavy
oil fields, and through intensified exploration and
more rapid development of newer oil fields are the important
- 18 -
facts of this strategy. To increase the indigenous oil production,
GOT encouraged The Turkish Petroleum Corporation (TPAO) to conduct
research ON EOR technology and implement EOR methods when feasible
in the fields as pilot application. It is in this setting that the
bati Raman EOR field demonstration project, and the Raman and
Hamitabat fields development projects were conceived. These projects
were the Bank's first involvement in the production of hydrocarbons
in Turkey.
II. PROJECT IDENTIFICATION, PREPARATION AND APPRAISAL
Origin of the Project
2.01 TPAO owns and operates 30 oil fields, of which about
12 have very small recoverable reserves of about 700 000 Bbl,
or less, and 5 gas fields. The oil in place of TPAO's oil
fields -s calculated as 3.810 billion STB in total of which
80 percent is under 20 AP! and considered heavy oil. The
primary recovery factors uf these reservoirs vary between
1 percent and 40 percenit depending on the producing mechanism,
oil and rock properties.
2.02 The Raman and Bati Ramnan fields are the most important
fields of TPAO. Bati Ranara contributed only 12 percent of
annual production, although it is the largest oil field so
far discovered in Turkey with an estimated initial reserve
of about 1.85 billion STB of oil. The recovery factor by
primary techniques for the Bati Raman field is estimated
at between 1.5 and 2.0 percent of the original oil in place.
This low recovery is due to the unfavorable properties of
the oil (such as low gravity, low solution gas, high viscosity)
and the absence of any appreciable driving mechanism. Because
of these adverse reservoir and fluid characteristics, the
field showed a fast production decline since the discovery
date of 1961. The original pressure of 1800 psi dropped to
about 400 psi and the daily oil production which was close
to 10000 BPD in maximum in 1969 dropped to about 1500 BPD
in 1985. This rapid production decline of the Bats Raman
field led TPAO to consider intervening with en'lanced oil
recovery (EOR) techniques.
- 19 -
2.03 EOR Technology in the world has increased since
1976. rhe primary stimulus for this activity was a significant
rise in oil prices. Although oil prices peaked in 1981 and
have since declined, extensive progresses in research and
field applications over this period have resulted in a better
understanding of the fundementals of processes applied. Since
conventional primary and secondary methods are
expected to recover only about one-third of the
oil originally in place, the remaining two-thirds of the
oil reserves,which are nonproducible due to adverse fluid
properties and reservoir conditions,constitute the main target
for EOR applicaticns in the world today. Therefore, the resources
to which EOR methods may economically be applied have a great
importance in the oil industry.
Preparation and Appraisal
2.04 In view of above considerations, in early 1978,
TPAO requested IBRD assistance in developing a program to
increase the ultimate recovery of fihe Bati Raman oil field
through the use of EOR technolr7y. Because a number of methods
which may enhance the oil reco ry could principally be used,
it was therefore decided to proceed in 3 stages.
'. To carry out a comparative evaluation of different
EOR methods to determine the most appropriate
method to be used.
2. To apply a pilot test of the method chosen to
evaluate its applicability to the field, and,
3. If positive results are obtained by the pilot
test, to extend the application of the EOR method
used to the whole Bati Raman field.
2.05 An engineering loan (S-13 TU) for USD 2.5 million
for the first stage of the project was approved by the IBRD's
Executive Directors in November 1978.
- 20 -
2.06 Using the funds provided for realization of the
first staye, TPAO contracted a consultant group (Intercomp
and Godsey - Earlougher) to carry out an engineering study
to determine the optimal techniques for increasing the oil
recovery from the field. In 1980, a comparative engineeting
study of alternative EOR schemes to be applied in the Bat.
Raman project was completed by the consultant. In this study,
6 EOR schemes were considered.
1. Improved recovery bI' chemicals,
2. In-situ combustion (dry and wet),
3. Steamflooding,
4. Steamflooding using USSR mining technology,
5. Waterflooding,
6. Carbon dioxide or Dodan gas application.
2.07 In this comprehensive prefeasibility study, the
reservoir response was evaluated providing project cost analysis
for various EOR schemes. The study concluded that both carbon
dioxide and steam injection applications were favorable.
However, immiscible carbon dioxide application appeared more
feasible because of the nearby Dodan carbon dioxide gas reserves
and the high initial investment cost of steam injection.
As is a standard practice for EOR projects, a de-nonstration
test should be undertaken to determine whether the technology
will, in fact, produce the expected results before the full
- scale application of the technology is applied.
2.08 During the final stage of the Bati Raman EOR study,
GOT requested assistance not only to undertake a field
demonstration test for Bat. Raman, but also lor the development
of additional reserves in the Raman oil field, and in the
assessment of the production potential of the Hamitabat gas
field in Thrace, northwestern Turkey.
2.09 In 1980, a loan agreement was signed between TPAO
and the IBRD in an amount of USD 62 million for the implementation
of 3 projezts in the Bati Raman and Raman oil fields, and the
Hamitabad gas field, as described in the following.
- 21 -
Project Description
2.10 The main objectives of the project were to increase
Turkey's oil production in a short term by developing the
newly discovered oil reserves and to expand Turkey's recoverable
reserves and enhance its medium-term oil production capacity.
These objectives would be achieved by the implementation
of the following 4 subprojects.
1. The Bati Raman Field Carbon Dioxide Injection
Project: A field demonstration project of the
chosen carbon dioxide injection technology would be
conducted on a linmited area of the Bati Raman field for the
purpose of evaluating the suitability of this
technology for full-scale application, and
determining the data required for designing the
whole field project. The oroject covered the
construction of a 75 km pipeline to transport
50 MMSCFD of carbon dioxide gas from the Dodan
gas field to the Bati Raman field; the installation
of associated surface systems at both fields;
the preparation of 25 wells and the drilling
of 5 additional wells in the Bati Raman field;
the application of the above mentioned technology
and the evaluation of the results.
2^ The Raman Field Development Project: A production
project covering the cost of 18 new production
wells and associated surface equipment in the
northern extension of the Raman field and a
reservoir analysis study determining the optimum
approach to a secondary recovery program for
the field.
3. The Hamitabad Gas Field Stimulation Project:
An evaluation of the production potential of
the Hamitabad gas field to provide reliable
estimates of gas reserves and productivity, and a
study to determine the optimum use of the gas.
- 22 -
4. The Management Study: Providing TPAO with assistance
for improving its operational productivity and
its management organization.
III. PROJECT IMPLEMENTATION
3.1. THE BATI RAMAN FIELD CARBON DIOXIDE INJECTION PROJECT
Project Management
3.1.1 The project management was entrusted to the TPAO Production
Department. To assist TPAO during the material procurement,
facility construction and the execution of the project, an
engineering agreement was signed between Williams Brothers
Engineering Comnpany (WBEC) and TPAO in 1981. Also, a contract
was sianed with TULAA5, a local engineering company, to supplement
WBEC's work domestically in the respective areas of the field
surface facilities design and the main pipeline. Two other
contracts were signed with The State Highway Department (TCK)
and The State Electrical Institution (TEK) for the construction
of 12 kilometers road from the state highway to Dodan plant,
ard the supply of 10 MVA electric power at 6.3 KV to the Dodan
plant, respectively. During the phases of material procurement
ard facility construction, contracts were signed with local
and foreign companies to carry out such works. kfter the
completion of construction works at Dodan and Bati Raman
areas, and before start of the carbon dioxide injection,
a new agreement was signed with WBEC in 1985 to provide TPAO
with procedures and reccmmnendations for operating the iroject
and for recording data and monitoring the project performance.
Project Cost
3.1.2 The first Loan Agreement dated November 30,1978
between GOT and IBRD has granted to TPAO in various currenries
equivalent to 2.5 million USD to assist in financing the
Bati Raman EOR Project. Upon successful ccmpletion of feasibility
study and the identification of promising EOR schemes outlined in
- 23 -
the final report, IBRD decided to encourage TPAO by a second loan.
The Loan 1917 TU dated November 24,1980, totaled 62 million USD
which also included refunding the first loan out of the proceeds of
the second loan. The original appraisal in the Loani Agreement
has been amended twice to reallocate necessary funds due
to special characteristics of the project. Annex 1 sets forth
the categories of items financed out of the proceeds of Loan
1917 TU.
3.1.3 As mentioned in Article 2.10, Loan 1917 TU also
includes the Raman and Hamitabat fields development projects
which are shown in categories 1-B and 1-C, respectively,
in Annex 1. When the sum of final appraisals for both projects
is deducted from the total allocated amount, the actual final
appraisal of the Bati Raman Project is 50.2 million USD.
Project Disbursement
3.1.4 The amount of money disbursed during the execution
of the project by the closing date of December 31,1987 is
shown in Annex 2. From the beginning to the closing date,
the total of 54 839 472 USD has been spent from the proceeds
of Loan 1917 TU. The realization is 89 percent which can
be credited as the result of close coordination between IBRD
and TPAO. Also, Turkish vendors, particularly civil contractors,
played important roles in the execution phase of the project.
However, in any case, it can be concluded that the project
tasks have been achieved within the budget which is a good
indication of efficient work of all the parties involved
in the project.
3.1.5 As mentioned above, the categories 1-B and 1-C in
Annex 2 also reflect the amounts for Raman and Hamitabat
fields development projects, respectively. When the sum of
disamounts for both projects is deducted from the total
disamount, the balance is the disbursement of the Bati Raman
project which was45 529 849 USD by the closing date.
Similarly, the remaining amount for the Bati Rdman project
was4 670 152 USD as of December 31,1987.
- 24 -
Procurement and Construction
3.1.6 The material procurement of the project was made
under the IBRD's procurement procedures. The International
Competitive Bidding (IC6) was applied to the materials procured.
The procurement of specialized natures was also done under
limited international biddings. In the initial stages of
project execution, some difficulties related with the IBRD's
procedures were en-ountered. This was generally due to the
TPAO's unfamiliarity to the rules of ICP and was eliminated
during the project period.
3.1.7 The project involved the procurement of different
types of equipment and materials necessary for the
implementation. These are divided into following groups:
Dodan-Bati Raman linepipes, gas compression system, Selexol
plant, dehydration unit, separators, manifolds, steam
generation system, instrument air system, off-gEs disposal
system, motor control center, central alarm system, chemical
injection system, pipeline appurtanences, field gathering
lines, surface and subsurface well equipments, electrical
equipment end controllers, water treatment system, and stock
tanks. Detailed information about these systems are given
in the following section. The material procurement list is
also given in Annex 3.
3.1.8 The construction of Dodan-Bati Raman pipeline was
completed between May 1982 and July 1983. Following the
material procurement, the construction of surface facilities
at both fields was commenced in May 1984. This work was
completed in October 1985. The construction of main pipeline
and surface facilities was accomplished by local contractors.
During the construction of surface facilities, some problems
related with the scheduling and cost was encountered with
the contractor. This brought both parties the court to
settle the dispute between TPAO and the contractor. In the
period from October 1985 until March 1986 when the gas
injection started, maintenance and testing of surface facilities
was completed.
- 25 -
Surface Facilities
Dodan Plant
3.1.9 The Dodan gas-processing and compression plant is
centrally located in the field and was designed for the Dodan
gas to be sweetened, dehydrated, compressed, and then transported
in dense phase to Bati Raman field by pipeline. The plant
is capalle of producing the equivalent of 60 MMSCFD of carbon
dioxide-rich reservoir fluid from 12 wells,of removing hydrogen
sulfide and water, and delivering about 55 MMSCFD or dry hydrogen
sulfide-free gas to the Bati Raman pipeline.
3.1.10 Fiberglass reinforced thermosetting resin pipes
(RTRP) were used as gathering lines to transport the reservoir
fluid from wellheads to the Dodan process plant. The design
includes provisions for the addition of heat at the wellhead
to prevent formation of hydrates in the flowlines from those
wells producing near the hydrate temperature. The fiber-glass
pipe is rated for 2000 psi, but the maximum allowable gathering
system pressure is 1200 psi as limited by stainless steel
316 L flanges used at the manifold and wellhead connections.
All flowlines at Dodan area are 4.5 in. in dianeter, insulated, and
buried. They had to withstand extzemely corrosive fluid at
1200 psi, and be installed in rugged terrain inaccessible
in some areas to tracked vehicles. These requirements called
for a system which did not require cumbersome construction
equipment and which could be repaired or expanded using
equipment readily available in Turkey. The major concern
regarding the use of RTRP was its lack of previous history
in high pressure carbon dioxide/hydrogen sulfide/water piping
systems; however, it has proven to be corrosion resistant
in a wide range of severe applications including downhole
service. Another concern was the relative susceptibility
of the pipe to mechanical damage, considering the toxic nature
of the produced gas. To minimize the potential for damage,
the flowlines were buried and stainless steel connections
to the wellheads and manifolds were tied in to the fiberglass
below grade.
- 26 -
3.1.11 TIle produced reservoir fluid includes free water,
carbon dioxide, and other hydrocarbon gases with some other
impurities. Free water is removed by means of two-phase
separators. Liquid carbon dioxide in the incoming stream
is evaporated using waste heat of compression from the
pipeline compressors. The gas is delivered to the Selexol
plant for the remova'l of hydrogen sulfide.
3.1.11 The produced reservoir fluid includes free water,
carbon dioxide, and other hydrocarbon gases with some other
impurities. Free water is removed by means of two-phase
separators. Liquid carbon dioxide in the incoming stream
is evaporated using waste heat of compression from the pipeline
compressors. The gas is delivered to the Selexol plant for
the removal of hydrogen sulfide.
3.1.12 The Selexol plant consists of two parallel 50 percent
trains, each capable of operating independently of the other.
This two train configuration also allows an effective gas
processing at rates below 60 MMSCFD. Operation at reduced
rates is also allowed when either one of the units is down
for maintenance. When operating at design conditions the
Selexol plant removes about 5 MMSCFD (8 percent) of the carbon
dioxide with the hydrogen sulfide. rhis hydrogen sulfide-rich
gas is disposed of by burning in an incinerator and venting
the sulfur to atmosphere in the form of sulfur dioxide. The
pipeline gas from the Selexol unit contains about 25 ppm
hydrogen sulfide by volume. After a preliminary evaluation
of possible separation systems, th- Selexol system has been
selected as the best one for Dodan service with the 700 psi
minimum plant operating pressure being a primary consideration.
Being a physical solvent, Selexol was able to use this relatively
high pressure to achieve a high acid gas loading and to largely
regenerate the solvent without heat by flashing the solvent
at lower pressures.The chemical solvent performance is
independ nt of pressure and is unable to capitalize on the
high absorber operation pressure. Another factor leading
to the selection of Selexol is its selectivity of hydrogen
sulfide over carbon dioxide of a factor of 9-10, capared to 4 for the
- 27 -
chemical solvent being considered. Equipment used in the
Selexol system did not require extensive use of special materials.
The Selexol solvent is both non-corrosive and has dehydration
properties. Thus, carbon steel surfaces wetted by Selexol
are normally protected by the solvent, and the carbon dioxide
gas in the equilibrium with the Selexol has a water dew point
below the operation temperature. Therefore, use of stainless
steel was generally limited to vapor sections isolated from
the main flow, such as bridles and PSV connections, where
film temperatures fall below water dew point during cold
weather. The one major exception to this was the Selexol
stripper and some related equipment. This equipment, which
is continuously exposed to saturated steam, carbon dioxide,
and hydrogen sulfide, was fabricated entirely of stainless
steel.
3.1.13 After sweetening, the gas coming from the Selexol
plant is dehydrated in a triethylene glycol system to 4-12 Lbs
water/MMSCF to prevent water condensation in the pipeline
at operating temperatures as low as 0 degrees centigrades.
This dew point specification allowed the use of unlined carbon
steel in pipeline construction, provided the line is buried
below the frost line. With the exception of the dehydration
system, plant facilities consist of two parallel process
trains each rated for 50 % of plant capacity. The single
dehydration system is rated for fuli capacity, but has spare
rotating equipment and high turndown trays in the contractor.
This design ensures effective operation at rates as low as
10 MMSCFD and also allows continued, reduced-rate operation
in event of failure of critical equipment.
3.1.14 The Dodan gas is compressed in two single-stage,
motor-driven reciprocating compressors to 1745 psi. The gas
is cooled, metered, and delivered to pipeline at about 1705
psi and 115 degrees fahrenheit.
3.1.15 The production and processing facilities at Dodan
are designed to operate at about 700 psi. As pressure falls
significantly below 700 psi in the future due to reservoir
depletion, it will be necessary to install a wet gas compreSsion
- 28 -
system at the inlet to the plant in order to maintain full
rate delivery to the pipeline. Such a system would compress
the gas from gathering system pressure to 700 psi. Thus,
the gas processing and pipeline compression systems would
not require modification.
3.1.16 A two-boiler, closed-loop steam system supplies
heat for the Selexol plant, glycol system, liquid carbon
dioxide evaporation coils, and fuel gas heater. The steam
system operates at 250 psi and is capable of delivering up
to 30 million BTU/hr. The normal steam demand is about 20
million BTU/hr.
3.1.17 An instrument air system supplies air for instrumentation
and controls as well as for pneumatic tools. It includes
two 100 % compressors to ensure availability.
3.1.18 The plant, the large portion of which was supplied
by Turkish -idustry, was manufactured to ASME codes. It was
preassembled and skidmounted complete with local control
panels by the suppliers. Normally, the skid assemblies were
functionally tested before shipping to the field. Produced-
fluid handling facilities exposed to wet carbon dioxide were
manufactured of different materials depending on the service.
In the plant area, corrosive service equipment and piping
were generally fabricated from stainless steel or stainless-
clad carbon steel. Thin film epoxy lining and fiberglass
pipe were also used in the plant in some low pressure and
marginally corrosive services.
3.1.19 Water supply for the plant is delivered fram a pump station
located on the nearby Basur river at up to 500 BPD. The water
ia stored at the plant and processed in a water treatment
system for use as boiler make-up and Selexol process water.
The incinerator and steam generators are operated with fuel
oil. The daily demand of fuel oil is about 15 tonnes. Primary
power of the plant is supplied by the national network. The
normal requirement of approximately 5.8 MWA is delivered to
theDodan plant site at 6.6 via a transmission line and
- 29 -
substation. Emergency back-up power is supplied by an on-site
125 kVA diesel-driven generator.
The Dodan-Bati Raman Pipeline
3.1.20 The 10 in. diameter, 80.5 km Dodan-Bati Raman pipeline
was designed in accordance with ANSI B31.8. It is constructed
of API-5LX X60 carbon steel pipe with wall thickness of
0.297, 0.307, and 0.438 in. The normal in.,et and discharge
pressures are 1700 and 1550 psig, respectively. The maximum
pressure is 2500 psi and occurs at the pipeline low point
during cold weather operation. The pipeline route passes
in the vicinity of several smaller heavy oil fields operated
by TPAO. There are five takeoff points so that the pipeline
can supply these fields in the future. Other features of
the pipeline, which varies in elevation from 1700 to 3700
feet above sea level, are three river crossing, three pipeline
valves, blowdown stations, and pigging and metering facilities.
Bati Raman Field
3.1.21 Much of the existing equipment at Bats Raman field
was incorporated into the design to minimize capital cost
while providing operational flexibility consistent with the
needs of the project. The western test area of Bati Raman
was designed for cyclic carbon dioxide injection and production
of 33 demonstration wells using transfer pump stations 3TP1
and 3TP2 as the centers for operations. Existing facilities
at the field consist of numerous remote manifolds which feed
into trunklines to satellite pump stations.
3.1.22 The western area carbon dioxide injection system
supplies approximately 20-25 MMSCFD of gas at about 1500
psi wellhead pressure to the demonstration we'lls operating
in the injection mode (up to 17 wells simultaneously). The
production facilities handle the oil, gas, and waiter from
up to 17 demonstration wells in the producing mode. The
3TP1 and 3TP2 pump staticns include facilities to evaluate
- 30 -
individual well performance, to remove produced water and
gas, and deliver the oilto theAPI main pump station fcr additional
dehydration and desalting. The gas produced from the demonstration
area is vented to the atmosphere.
3.1.23 Ideally, the gathering lines at the Bati Raman field
should be internally lined and use stainless steel valves
and fittings to withstand corrosion. They should also be
insulated to prevent heat loss and; consequently, high oil
viscosity. Without the use of lining and stainless steel
fittings, the flowline might be susceptible to rapid corrosion.
Without pipe insulation, high oil viscosity during winter
operations might limit flowline capacity, and therefore,
well production poential due to high flowline back pressures.
Owing to the expense of installing a new gathering system,
only a few of the new lines were included in the proposed
design. The performance of these lines is being monitored
to determine if a completely new gathering system is justified.
In the production system, where operating pressures are normally
be less than 100 psi, there is negligible hydrogen sulfide,
and initially, water is not present in the gathering system
as a continuous phase. Corrosion-resistant materials specified
for Bati Raman surface facilities consist primarily of fiberglass
flowlines (6 and 8 in. at 700 psi) on selected wells. Also,
thin film epoxy phenolic coating was specified for all new
in-plant piping and separators. This includes all systems
handling water-saturated carbon dioxide gas. In the Bati
Raman area, most of the existing carbon steel stock tanks,
pumps. flowines, and oipelines which were predominantly in
liquid service are being protected by injection of liquid
corrosion inhibitors.
Project Planning
3.1.24 In spite of uncertainties involved, the results
of initial comprehensive studies showed that a substantial
quantity of oil could be recovered by cyclic Dodan gas
injection possibily followed by water flood. The best way
this could be tested was in the field.
- 31 -
3.1.25 It was decided that a pilot be initiated to test
oil recovery by a cyclic Dodan gds injection, and depending
on early performance of the reservoir corrective measures would
be taken. The general area chosen for this demonstration
project is in the western part of the field, encompassing
about 1200 acres with 33 adjacent wells drilled in a five
spot pattern (Figure 1). To begin the operation, half of
the wells (first, third, and fifth lines of wells shown in
Figure 1) were planned to be used as injectors, and the other
half as producers. After about 3 months, when bottomhole
pressures reach about 1800 - 2000 psi, injectors were planned
to be converted to producers, and producers to injectors.
This mode of operation, i.e. out of phase stimulation of
adjacent wells was based on the assumption of a single porosity
system. When a well experiences the injected Dodan gas, neighboring
wells were planned to be put on production so that the injected
gas could be readily move out from the well and finger through
the oil allowina diffusion. In this case, gas break-through
should not occur for a long time. If the reservoir in
all or in part of the test area is closer to a dual-porosity
system, then break-through in the producers should occur
early during the scheduled first injection cyc.le. In that
case, the operation was planned to be converted to in-phase
cyclic stimulation of one half of the area at a time. Thus,
while the eastern half was being stimulated, the western
part should be on production, and vice versa. Durirg the
implementation of the project, both conditions, buc mostly the
existance of the dual porosity system, have been experienced
in the pilot and vicinity areas. This will be discussed in
the following sections.
3.1.26 Initial work for the start uD of the Bati Raman
EOR demonstration project was commenced in November 1985,
and consisted primarily of establishing project monito-ing
procedures for the start up, organization and implementetion
of the computer database system and the reEervoir simula:or.
Past performance and core and log data of the Bati Rainan
wells were reviewed in 1985 for the development of a reservoir
- 32 -
model suitable for the simulation work. Initial simulation
work consisted of single-well huff and puff simulations.
This early work demonstrated the importance of buildirg
reservoir pressure to a level where carbon dioxide solubility
reaches significant levels. It also showed that ap?lication
of the huff and puff process would require contai:.ment of
the carbon dioxide within the demonstration area.
3.1.27 After the new agreement was signed with WBEC for
monitoring the pilot application, J. S. Nolen and Associates's
Dual VIP simulator was used for simulation studies. This
simulator is a tnree-dimensional, three-phase, dual porosity,
"black oil", reservoir simulator which accounts for diffusion
of gas between fracture and matrix and the 3olubility of
carbon dioxide in water. Simulation runs were made on a Microvax
II computer for about a year. and in December 1986, the simulator
was installed on the VAX 11/750 computer located at the TPAO
Production Group office in Ankara.
3.1.28 The simulator used in the simulation studies made
in 1979 was not a dual porosity simulator. In that study,
reservoir fracturing was accounted for in a simplistic and
non-rigorous manner. It was not until several years after
the first simulation study was performed thLf technology
for rigorous, dual porosity simulation became available.
Also, the simulator used in the 1979 study was not fully
implicit and therefore could not run radial, single well
simulations in an efficient manner. As a result, all studies
of single well processes such as huff and puff, were done
in cartesien coordinates. Results obtained when simulating
a single well in this way differ significantly from results
obtained using current simulators.
3.1.29 The reservoir simulation technology has been improved
considerably since the previous study was made. An entirely
new generation of reservoir simulators was developed during
this time. Also, considerable advances in methods and techniques
for applying simulator results was made. Therefore, it should
not be surprising that the results and conclusions obtained
in the final simulation studies are different from those of
- 33 -
the previous ones.
Well Design
3.1.30 rhe principal design criteria for the wells in
Dodan area was the extensive corrosive environrent. The
production casing is 6 5/8" J-55 and was cemented is 2 7/8"
in grade L-80 with plastic coated internals. The producing
formation was isolated by hydraulically set p3rmanent packers
at the top. Wellhead, gauges, needle valves, adjustable
chokes and master valves had been trimmed for hydrogen
sulfide and wet carbon dioxide services.
3.1.31 In the Bati Raman pilot area, 29 of the pilot wells
were completed with single tubing and packer. Both injection
and production is being done through the 2 7/8" tubing.
Following the injection cycle, the well is allowed to flow
through the tubing. When pressure is depleted and the wells
stop flowing, the pump and rods are run into the well. At
the end of the production cycle, the pumps and rods are
pulled out and the injection tree is re-installed. For this
switching operations a pulling unit is required. In the
pilot area, a dual tubing completion, one for injection
and the other for production, was designed for the
remaining 4 wells. For existing 6 5/8" casing wells, 2 7/8"
and 1.9" strings were run with dual hydraulically set packers.
By this design, the rods and pumps do not needed to be
used for fluid entry surveys. Also, in the pilot area,
5 wells in key locations are equipped with pressure -
temperature sentry systems. All pilot wells have 2"
bottomhole gaseous puirips with D-320 pumping units.
- 34 -
3.1.32 Corrosion is not significant during the injection
cycle as the Dodan gas should be dry and virtually free of
hydrogen sulfide and other contaminants. Although the
downhole equipment is subject to a wet carbondioxide environmen;.
during production, the tubing is not plastic coated since
the coating is eroded by rod action during the pumping
cycle.
However, during the project execution, corrosive acti.ons
shown in downhole equipment has not been found serious.
An oil soluble, water dispersible corrosion inhibitor is being
squeezed after each well is put on production and just before
the start of the first carbon dioxide injection cycle.
Each producer is then resqueezed before pumping operations
start. In the pilot area, all wellheads, gauges, valves,
needle valves, tubing hangers and master valves were
trimmed for wet carbon dioxide service.
Project Execution
3.l.33 The Dodan - Bati Raman pipeline was first used to
transport the Dodan gas for the pilot project application
in the Bati Raman field on March 19,1986 after the surface
facilities at Dodan plant had been tested for maintenance
and performance. However, particularly due to the
malfunctioning of the main line compressor, continuous
gas injection could not be achieved and the injection was
stopped 6 weeks later. During this 6 - week period,
a total of 520 MMSCF of gas with 12 MMSCFD average flow
rate was injected into the Bati Raman reservoir through
16 injectors located on the first, third and fifth rows
- 35 -
in the pilot area (Figure 1). Injection was restarted in
July 1986 following the completion of repairs and restoration
on compressors and other facilities at the Dodan plant. But,
because of necessary modifications of the compressors and
the incinerator, the injection was had to be stopped again
several times , totally about 6 weeks, until November
1986. Between August and November 1986, a continuous 2.5 -
month injection was firstly accomplished with an average
rate of 22 MMSCFD. In a 3 - week stop in November 1986, the
compressors and other systems were readjusted and the whole
system at Dodan plant was reexamined. Starting from this
date up to now, continuous injection was accomplished
at an average rate about 20 MMSCFD, except for two stops in
October 1987 and January 1988 for maintenance and some
repairs. Also, for testing purposes, the injection rate
was increased to 48 - 50 MMSCFD in February 1987. The
injection profile of the project is shown in Figure 3.
In September 1988, the total amount of gas injected into
the Bati Raman reservoirs was 14 MMMSCF since the beginning
of injection. Currently, injection continues at a rate of
18-20 MMSCFD.
3.1.34 On the other hand, as far as the pressures and
flow rates of Dodan wells are concerned, all the
observations were positive during injection of gas
at an average rate of 3 MMSCFD per well and a maximum rate
of 6.5 MMSCFD per well into 10 Dodan wells that have an
average of 1000 - 1100 psi dynamic wellhead pressures.
- 36 -
3.1.35 Before start of the injection, wellhead pressures
of 18 injection wells were in the range of 300 to 500 psi
in the pilot area. After the injection was started, it was
observed that the injectivity of wells located in the eastern
part of the pilot area was comperatively higher (1.1 MMSCFD)
than that of the wells located in the western part (0.4
MMCSFD). After observing gas coming out of the wells * 171
and v 197 in the pilot area and the vicinity well a 112 at
the east of the pilot area, the injection into 9 wells located
at che east half of the pilot area was temporarily stopped
in order to prevent the migration of gas to where the
reservoir pressures was relatively low. The Kh factor
was improved in the central area of the field. Meanwhile,
since the designed injection pressure of 1500 psi could not
be maintained earlier, the injectivity of wells located in
the west part of the pilot area was improved to a reasonable
level as those wells in the eastern part were closed to injection.
After obtaining a sufficient pressure level,the wells previously
closed were put on injection again in October 1986. Since
then, the injection has continued mos2.-y into 18 wells in the
pilot area, and in that period 9 injectors were put oir production
mode according to the designed "huff and puff" application.
3.1.36 In September 1986, in order to prevent the migration
of injected gas to the central area of the field and in order to
have a more effective injection in the pilot and vicinity
areas, water injection was started with the rate of 5000 BPD
into the wells w72, w33, v99, and f69 located on the boundary
line between western and central areas of the field (Figure 1).
By this applicatior, the injected water formed a barrier between
the central and western areas preventing injected gas from
escaping fran the western to the central area of the field.
The water injection continued for 9 months until May 1987,and
in that period an effective pressure barrier was obtained
in the mentioned area which was about 900-1200 psi at the
west of injectors #72 dnd r33, and 800-1200 psi at the south
of injectors 169 and p99. No gas break through was observed
and also the injected water had partially effected the central
area of the field resulting in production increases in some
wells. During that period, a total of 950 000 Bbls of water
was injected into the Bati Raman reservoir.
- 37 -
3.1.37 During the project application, pressure develcpment
has been observed by periodic surveys in the pilot area and
surrounding wells. Wells #107 and #118 located on the injection
lines and wells 172, 182 and 194 located on the production
lines were initially selected as key wells for continuous
pressure and temperature surveys. Pressure profiles recorded by
these wells is shown in Figure 3 except well #107 at which
the pressure/temperature sentry system failed. The bottomhole
pressures that were less than 400 psi in early stages of the
injection scheme in wells f172, 0182, and #194 rapidly increased
after the continuous gas injection has effected their areas
starting from October-November,1986. The pressure in wells 172
and 194 has reached levels up to 1350 psi, and in well #182
the pressure increased to 1850 psi in March 1987. As can be
seen in Figure 3, this was a result of high injection rates
tried only for testing purposes for a 3-week period. The primary
purpose was to test the injection capacity, but it also showed
that higher injection rates didn't result in significant changes
in production rates, so the injection rate was maintained
at about 25 MMSCFD between March and July 1987. Due to the
increase of the back produced carbon dioxide gas, the injection
rate wa3 decreased to 15-18 MMSCFD between July 1987 and March V
1988. After that date a good injection/production balance has
been achieved by an injection rate around 20 MMSCFD. As also
seen in Figure 3, the bottomhole pressure in well #118 which
was an injector at that time increased rapidly to 2500 psi
during the first few months of the injection. Then, it decreased
to 1000 psi due to interruptions of injection until August
1986 when a continuousm injection was achieved. The pressure
increased again starting from that date, and in October 1986
it reached 2300 psi. This well was put on production in
November 1986, and therefore the pressure profile shows a decline
after a soaking period from that date until February 1987.
Since then, the well has been on production and has about 600 psi
dynamic bottomhole pressure. The static bottomhole pressure of
key wells was calculated to be about 1700-1800 psi when the
reservoir was pressured up by continuous injection. This
pressure level was achieved in March-June 1987 and it has been
maintained since then. The gas that was injected in almost
all directions in the central and more heavily in the eastern
- 38 -
regions of the pilot area generally tends to migrate to the
structually higher portions of the reservoir where large fractures axit,
causing high pressures in those portions. This situation,
in one respetct, can be verified since the recoveries of the
production wells in the pilot area increase with the increasing
rate of gas backproduction. For example, the production in
well #173 located in the center of the second line of the
pilot area has exceeded 300 BPD with a gas backproduction
of 1 MMSCFD; and over 200 BPD of oil has been produced with
a gas backproduction of 1 M.MSCFD from well #193 located in
the fourth line of the pilot area. Starting from March 1987,
a high pressure area was observed initially at the second and
fourth line producers of the pilot area as recorded by the
key wells. Also, static bottomnhole pressure measurements
made in surrounding wells showed high pressure areas initially
at the first line of the southwest pilot area. On the other
hand, pressures in the areas where wells =112 and =68 are
located east of the pilot area and wells =153 to =102 are
located as a line north of the pilot area remained low. This
was explained possibly by ar. existence of a low permeability
barrier between these areas.
3.1.38 During later stages of injection, it was observed
that high pressure areas extended to the all surrounding
parts of the pilot area. In the beginning, it was expected
that the production increase would take place only within
the drainage area of the injectors by the application of
"huff and puff" method. However, as the pressure i..vreasa
was continuing and spreading over the whole pilot area and
most of the surrounding wells, it was seen that the "huff
and puff"a'zolication turned into a more effective gas drive.
This is one of the most important results obtained by the
field application cf the Dodan gas injection.
3.1.39 Most of the production wells that were previously
shutdown because of the low reservoir pressure in the pilot
and vicinity areas were then put back to production as
fluid levels increase due to the gas injection. Hence, the
- 39 -
total production rate of the 3 main gathering systens (3TPI,
3TP2, and AP1) of the oilot area and surrounding wells increased
from under 300 BPD before March 1986 to over 1000 BPD in
April 1986 because of the additional producing w.ells being put
on production with higher fluid levels. Oil production and
gas backproduction rates and gas-oil ratios of these 3 gathering
system are shown in Figure 4. In Figure 5, oil production
and gas injection/backproduction of the "test field" (Pilot
and the vicinity areas) are also shown in daily and cumulative
figures covering all 3 gathering systems. As seen in Figure
5, since the injection was temoprarily stopped for 3 to 4
months until September 1986, the production of the test field
declined to the 800-900 BPD level;once the injection was restarted
the production Luoe back to 1200 BPD in October 1986, 1400
BPD in January 1987 and over 2000 BPD in March 1987. Production
increasescontinued and reached, 3000 BPD in July 1987 (Figure
5). Since then, over 3000 BPD production was obtained from
the test field and in September 1988 it reached 3700 BPD.
3.1.40 The number of production wells from which the injected
gas is back produced has increased along with the injection.
Although there were only 2 to 3 wells that back produced
gas in April 1986, the number of gas back producing wells
have increased to 12 in the pilot area and 5 in the vicinity
area in March 1987. Ir. September 1988, the gas back production
spreaded over all producing wells in the pilot area and 15
vicinity wells. The first gas break through was observed
in well #112 and then well p120 which are located where Kh
contours have higher values. Although a gas flow in the direction
of those wells was observed in the beginning, there was
not a considerable gas flow from the other vicinity wells
later. Starting from October 1986, the gas back production
rate reached to 1-2 MMSCFD in December 1986 and exceeded
4 MMSCFD in March 1987. As the oil production increased in the
pilot and vicinity areas as a zesult of the continuous injection,
the gas back production also increased (Figures 4 and 5).
It was over 10 MMSCFD in September 1987. Considering the
maximum capacity of the separatinq system in 3TP1 and 3TP2
stations which is 12 MMSCFD, some adjustments were made in
the injection programme. After the injection rate was fixed
at around 18-20 MMSCFD, the gas back production rate was
- 40 -
maintained at less than 10 MMSCFD since last September. It
was 9.4 MMSCFD in September 1988. After the installation
of re-cycling of the project extension, re-injection of back
produced gas will be accomplished.
3.1.41 The aim of "huff and puff" application for the pilot
prolect was to increase the bottomhole pressures of the wells
up to 1300-2000 psi level and put the wells into production
after a soaking period. Once the pressure had reached the
desired level, the injection wells 150, 118, 214, 156, 117,
116, 115, 103 and 108 were put into production between November
1986 and February 1988. General production performance of
these wells is as follows. As the wells are put on production,
the gas starts to be produced at a rate at about 1 MMSCFD,
and within the following few days oil production starts together
with the gas in a flowing phase. The well generally flows
about 1 to 2 weeks depending on the pressure decrease. The
average recovery of the wells is about 100 BPD in this period.
After the well is placed on pump, the production
continues with the rate of 50-60 BPD for 2 to 3 weeks, then
it gradually decreases to 25-30 BPD level within 2-3 months.
O.n the other hand, the GOR is very high in the beginning when
the well flows. In the pumping mode, it decreases below 10000
SCF/STB, and continues to decrease gradually until i: reaches
almost a constant value at about 3000 SCF/STB in few months.
The only exception to this behavior is well 118. When this
well was first put on production, a high flow rate of gas with
no oil was observed for about 2 weeks. Then the well started
to produce oil in increasing rates up to 60 BPD. In September
1988, this well has almost 2 years production life after
the injection mode and produced at a constant rate of about
50-60 BPD. Although the well wasn't put on injection mode again,
a continuous oil recovery at about the same rate was obtained.
This behavior demonstrates the areal pressurized reservoir
effect rather than the "huff and puff" effect.
3.1.42 The total production of Bati Raman field has noticeably
increased when compared to the primary decline of the field
for mid 1982 due to the water injection applied in various
- 41 -
patterns in between 1972 and 1981; however the production
returned to its original primary decline after 1982 (Figure
6 and 7). The daily production of the field which was 2500
BPD in 1982 had declined to 1500 BPD lust before start
of gas injection. The total field production has also risen
along with the gas injection becoming 1750 BPD in May 1986, 2000
BPD in September 1986, 2500 BPD in February 1987, 3000 BPD
in March 1987, 3500 BPD in June 1987 and 4000 BPD in July 1987.
Since then, the production capacity of the project area
has been at the same level, and the total field production
has averaged around 4000 BPD. In September 1988,01o1 production reached
4600 BPD. If the gas injection had not been implemented,
the production decline curves for the field ssiow that the
primary production would have been 1000 BPD as of September
1988. In consideration of that fact, there has been. a production
increase of 3500 BPD as of September 1988 which corresponds
to a 4.5 fold increase in production.
3.1.43 In Figure 8, the Bati Raman project injection-production
efficiency is reptesented. In this figure, the incremental
oil produced from 3 main gathering systems of the project
area is plotted vs. the total gas injected since the beginning
of the ga3 injection. It can be deduced from the slope of
this curve, especially upon considering the production increase
since the second half of 1987, that 5000 SCF of gas is needed
to be injected for 1 STB of oil produced. This ratio is two
times smaller than the average figure of 1 STB/10000 SCF,
given by the industry.
3.1.44 Since the beginning of the project application,
all field data has been recorded by the Ingres Data Base
System to the VAX 11/750 Computer System installed at TPAO
Production Group in Ankara. This evidently provided easiness
to the project monitoring. Figures 9 and 10 are given as
examples showing injection and production histories of 2
wells, one injector and one producer, respectively. Similar
figures for all of the wells existing the pilot and vicinity
- 42 -
areas can also be^n obtained. Figure 11 has been used to
follow up the final status of wells existing in the 3 main aathering
systems. Also, distributicns of pLoduced oil, pressure and
GOR contours in the project area can be obtained in X,Y,Z
coordinates systems. Figure 12 thru 14 represent these
distributions.
3.1.45 The Bati Raman reservoir simulation model studies
showed that more economical recovery could be obtained by
a pattern drive process utilizing both carbon dioxide and
water. it was proposed by our consultant (WBEC) that the
benefits of a WAG (water alternate gas) drive process were
dependent upon the water imbibition characteristics of the
Bati Raman reservoir rock. As the available laboratory
and field data we,e insufficient to determine these imbibition
characteristics, it was decided that the best way to evaluate these
characteristics was with a field pilot.For this purpose,2 gas injection wells
(#107 and *148) at the west side of the pilot area were chosen
as water injectors (Figure 1). In March 1988, water injection
st2rted in these 2 wells at a total rate of 500-600 BPD.
Wells s176 and #177 east of the injectors were chosen
as observation wells. In April-May 1988, the effects of water
injection were started to be observed in these 2 wells with
increasing water cuts. Although the total injecticn rate
was dropped to 300 BPD in June 1988, the increase in water
cut continued up to about 70-80 %. In September 1988,the
total amount of injected water was 130000 Bbls, however there
was no remarkable increase in the oil production of the observation
wells.Before the start of the water injection, production rates
fram the observation wells had reached over 100 BPD due to
the injected gas which was about 1 MMMSCF in total from wells
#107 and p148. During water injection, high water cuts caused
a drop in production of the observation wells down to the 40-50
BPD level. On the other hand, in well t175 which is located
north - east of the water injector #148, a production
increase above 100 BPD was observed after the start of water
injection. This increase could be due to the effects of gas
injectors #214 and #150 located at north of this well, however
- 43 -
it. is also believed that a sufficient pressure increase might
be supplied to the vicinity area of this well by the effects
of w;ater injection from well 0148. This is not proved yet,
because no water has been produced from 0175. The pilot
application of the WAG project has been continued, however field
results obtained up to now suggest that it has not yet shown
promise.
Performance Analysis
3.1.46 Conventicnal use of carbon dioxide for improving
cil recovery has been mostly confined to miscible applications
where the displacement of crude oil from pore space in rock
is achieved by a solvent action that prevents formation of
interfaces between driving and driven fluids. However, in the
Bat. Raman field, such miscibility could not be obtained
and has not been a factor in increased oil recovrery. Rather,
the enhancement of oil recovery should result from the high
solubility of carbon dioxide in iow-gravity oil. The initial
model studies had shown that the major task of the project
was saturating substantial quantities of oil by cyclic
injection of Dodan gas. The process has began by repress3ring
portions of the reservoir withl DDdan gas allowing it to diffuse
into the oil it contacts. Oil recovery by Dodan gas diffusion
is the primary mechanism in which Dodan gas can dissolve in
oil, causing oil swelling and viscosity reduction. But, diffusion
requires a long time iefore a substantial amount of reservoir
oil can be treated. Before diffusion can work as a practical
means of treating large volumes of oil, it is necessary that
the injected gas effectively penetrate the reservoir and
provide a large areal contact.
3.1.47 Simulation of past performance data of the. field
and water-flood pilots had shown enough evidence that a dual-
porosity system dominates at least in certain parts of the
reservoir while a combination of duel and single porosity
systems can be effective in other portions. The nature
of the dual porositysystem with its highly conductive and
low fracture network, is conductive to an effective penetration
- 44 -
of the reservoir as Dodan gas moves through the fractures.
Thus, a dual porosity system has the basic requirement for
success of oil treatment by Docan gas. In a single-porosity
system where the fracture network is absent, extensive fingering
of Dodan gas through the oil would be necessary to provide the large
areal contact needed for diffusion to be effective.
3.1.48 Once the reservoir is pressurized up to 2000 psi
and saturation is achieved to a considerable extent, the
wells are depleted and a typical solution gas drive performance is
expected. In the "huff and puff"model, the pressuring and
depressurina cycles, each aiming to contact further virgin
oil, should be repeated several times ur.til all recoverable
oil is produced Initial model runs had indicated that up
to 25 % of initial oil in place could be recovered by cyclic
methods depending on unfavorable or favorable selection of
parameters involving some uncertainties, well spacing, and
number of cycles. This would also result in about a tenfold reduction
in oil viscosity and approximate 20 percent increase in volume
at the res_rvoir pressure of 2000 psi. After a large volume
of oil has been saturated, operating alternatives should
include a) Continuing with cyclic Dodan gas stimulation,
or b) Water flooding the saturated oil. However, during the
field application of the project, well performances have
sh3wn that the most of the production increase was coming
from wells benefitting from a 'gas drive" mechanism rather
than cyclic injection. This was also proved by recent model
runs matching with field results. These studies show that
a drive pzuc,.bb using only carbon dioxide results in an
ultimate recovery of less than 10 % of the original oil in
place. This behavior of the Bati Raman reservoir led us to make
the necessary changes in the injection scheme considering
the gas drive pattern.
3.1.49 The Bati Raman project has been monitored using
reservoir simulation models. The objectives of simulation
studies were to develop an operational plan optimizing oil
production at the Bati Ramr-an field by Dodan gas injection,
- 45 -
to use a reservoir simulation model to match reservoir
response to gas injection in the pilot area and to predict
future performance. J. S. Nolen and Asscciates' Dual *'IP simulator
has been used in these studies. The simulator is a three-
dimensional, three-phase, dual porosity, "black-oil", reservoir
simulator which accounts for diffusion of gas between fracture
and matrix and the solubility of carbon dioxide in water.
A radial geometry was used for analyzing the "huff and puff"
performance, while an 1/8 element of symettry of a 5-spot pattern
was used to study the gas flood performance.
3.1.50 General characteristics of the "huff and puff' cycles
were that when the well is put on the "puff" cycle, the flow
stream is only gas initially, followed by increasing oil
and decreasing gas production, as pressure around the wellbore
decreases quite quickly. A radial model match of this
performance (Figure 15) indicates that the fractures around the
wellbore are fully saturated by gas when the well is initially
put into produztion. It is only after all of this free gas
is produced, and relative permeabilities to oil in the fractures
are restored, the oil production starts. Thus, the oil is
fed to the fractures from the matrixes. The permeability
of oil in the matrix determines the Lil production at the
wellbore. Because the pressure declines by this time around
the wellbore, also causing dissolved gas to liberate, the
oil production from the weLls remains at 20-40 BPD level.
3.1.51 A significant observation at the field was made
that a considerable amount of oil was being produced due
to the flooding effect of gas. Therefore, the gas-flood performance
in a 5-spot pattern was studied. Producing well #182, with
4 injectors #116, 117, 108, and 109 (Figure 1) was simulated.
The basic results of this work is as follows.
a) The reservoir behaviour is clearly dual-porosity.
b) The observed breakthrough on production wells
is after-3-6 months of effective injection. This can only
- 46 -
be explained by diffusion of carbon dioxide into the oil.
If there were no diffusion, the gas would have broken through
in less than a month. The model studies also indicate that
gas solution in the matrix blocks is a function of the "diffusivity
constant" and the "matrix and fracture exchange coefficient"
which is a function of matrix block sizes (which is also
indicative of fracture intensity). As the diffusivity constant
is more or less fixed by laboratory measurements, it becomes
a matching parameter.
c) In the 5-spot pattern simulation study, the break-
through times, bottomhole pressure, gas and oil production
rates were matched. This match explains the reservoir recovery
mechanism as follows. The injected gas initially comes into
contact with the oil in the fractures and dissolves in it.
Meanwhile, the gas also diffuses into the matrix blocks.
However, since tnis is a slow process, the oil in the matrix
blocks always remains unsaturated. As the oil in the fractures
becomes saturated, the free gas saturation builds ip in the
fractures and then the gas/oil ratio increases. After this
71oment, the only thing that stops the gas coming to the
wellbore is its diffusion to the matrix blocks. Therefore,
after some tirre, most of the gas is cycled, however the oil
production is still considerable (Figure 16). After gas
b.-eakthrough, the pressure in the reservoir goes to a declining
trend causing the fracture solution gas to decline too (Figure
17). When the injection rates are decreased the gas/oil ratio
is improved immediately (Figure 18), but too much lowering
will cause the pressure to decline. In this case, there should
be an cptimum injection rate.
G) The results of simulation model studies show
that economic oil can be recovered by optimum injection rates for
a long time. Field results obtained later provided evidence that
the model is succesfull in predicting the gas-flood performance.
Project Expansion
3.1.53 When all "huff and puff" wells a-ere compared with
the other production wells in the pilot and vicinity a-eas,
- 47 -
it was observed that almost all of the wells in continuous
production modes have had much higher recoveries. As of Se.:ptember
1988, the incremental oil recovered by the imple-rontation
of the project was over 2 RMSTB. Until that date, only about
10 % of the production increase has been obtained from the
"huff and puff" wells and 9G % from the other producing
wells. After 1 year of field experience following pro,ect implementatic
it was finally interpreted that the production increase was
comirg from wells benefiting from a "gas drive" mechanism
rather than a cyclic injection. Reservoir model studies as
mentioned above also matched with the field results that
the prevailing recovery mechanism in the project area was
gas drive.
3.1.54 Field results also showed that the maximum oil nroduction
of the field by the project implementation at the west part
of the field would be around 4000-5000 BPD. To accelerate
the oil production, it was ccnsidered that the best way would
be the expansion of the project area towards the middle of
the field. 11out a 10 fold production increase at the project
area encou.aged us to make this step. Considering the gas
drive mechanism, necessary changes were made in well patterns
and a new area covering about twice as large as the existing project
area (Figure 19) was planned for the project expansion. In
this application, all injectors were considered in continuous
injection mode shown on Figure 19 which required 36 producers
to be converted to injectors. Also, in the extended area,
new producers were planned to be drilled. Sixteen wells,4 in 1987
and 12 in 1988, are already drilled and completcd. For
1989, the drilling of 14 new wells is planned. In addition,
workover operations have been carried out in all existing
wells in the expanded area. The large scale commercial expansion
of the Bati Raman project covers new injection and production
lines and manifold systems; additional separating systems
having the capacity of processing the back produced gas from
the expanded area, and re-cycling compressors and dehydration
systems in order to recompress this gas back into the reservoir.
TPAO is now in the construction and procurement phase of
above mentioned work. The large scale project is planned
to be completed in 1990. By the implementation of new project,
- 48 -
oil recovery from the total field is estimated to increase to
around 10000 BPD.
Conclusions
3.1.55 Implementation of the Bati Raman EOR project has reflected
general characteristics of a field pilot application as being either
the reservoir behaviour or the problems encountered in surface
systems particularly in early stages. The heterogenous structure
of the Bati Raman reservoir and especially the thermodynamic
conditions of carbon dioxide have formed a rather complex behaviour
for the operating systems. The information gained during project
implementation has guided us for the future operations
of the project. As of September 1988, the general conclusions
of the Bati Raman EOR project are as follows.
a) The amount of cumulative gas injected into the
reservoir is 14 MMMSCF, averaging about 20 MMSCFD
for the operating period. Also, approximately
5 MMSCF of gas has been back produced with the
oil from the pilot area. This represents about
35 % of the total gas injected. By the application
of project expansion, the back pioduced gas is
planned to be re-injected into the reservoir by
the use of re-cycling compressors.
b) Positive results of the pilot project application
have being observed starting in March 1987.
The total production rate of tne 3 main gathering
systems (3TP1, 3TP2, and AP1) which was about
300 BPD before the start of the gas injection has
exceeded 3700 BPD. The total production rate
of the field has reached over 4600 BPD whereas it
was estimated to be around 1000 BPD on primer production
This corresponds to a 4.6 fold increase in production.
The total amount of incremental oil produced
since the start of the project application is
over 2 MMSTB. When the incremental oil produced from
thc 3 main gathering systems is compared with
the total gas injected, it can be concluded that
5000 SCF of gas needs to be injected for
1 STB of oil produced.
- 49 -
c) Field results showed that m)st (about 90%)
of the observed production increase is coming
from wells benefitting from, a gas drive mechanism,
rather than the cyclic injection wells. Even
the average well performance is clearly better
in the former group of wells. It is observed
that the injected gas moves to the upper parts
of the Bati Raman structure creating a gas flood
effect. In general, early breakthrough has not
been observed except in a few wells due to the
solubility of the injected gas.
d) Simulation studies also confirmed that the gas
drive yields a higher recovery than "huff and
puff".
e) Field results of the applied WAG project show
that it has not yet shown promise.
f) The above results of the Bati Raman EOR pilot application
indicated that the expansion of the project could
be economically attractive. Considering the gas
drive production mechanism, a large scale EOR
project (covering twice the area of the existing project
area) is planned.
g) During the project application, 16 new wells,
4 in 1987 and 12 in 1988, were drilled and completed
in the Bati Raman field. Stimulation operations
were also applied to all iiijectors and producers
in the project area. For 1989, the dri lling of
14 new wells are planned.
h) By the successful application of the Bat. Raman project,it
can also be concluded that TPAO engineers and
technicians working on the project have had
opportunities to improve their technical skills
and capabilities by attending courses and seminars,
and mostly by working with responsibilities in
their areas.
- 50 -
3.2 THE RAMAN FIELD DEVELOPMENT PROJECT
3.2.1 Raman oil field is the second largest oil field
of TPAO with 600 MMSTB oil-in-place and 60 MMSTB recoverable
oil. Raman oil has a grality of 180 API. Heavy oil, the faulted
and naturally fractured nature of the reservoir, and the
existence of active bottom water complicate the production
characteristics of the reservoir. The Raman Field Development
Project was initiated to investigate improving the oil production fron
this field by conducting an extensive study on the reservoir
and production characteristics of the field together with
the conduction of an EOR Study to determine the EOR method
applicable for the reservoir. Later, the reservoir and EOR
study of Garzan field was also included to the scope of the above
mentioned project. Garzan-B and Garzan-C reservoirs contain
300 MMSTB of 240 API gravity oil with 42 MMSTB of recoverable
reserves. These fields have been subjected to waterflooding
since 1960.
3.2.2 In November 1982, an RFP was prepared and forwarded
to six prequalified reservoir engineering consultant
companies. Five companies forwarded their proposals to TPAO.
An evaluation committee worked on the proposals and forwarded
the evaluation report to IBRD for concurrence in April 1983.
Upon the concurrence of IBRD, the bidder with the highest
points,Intercomp, was invited to TPAO for the final contract
negotiations. After the completion of the contract negotiations
with 7ntercamp for a "Ccoparative EOR Study for Raman and Garzan
fields", the final agreement was signed by both parties in
September 1983, and the project was officially initiated
on Septemberl9,1983 in Calgary.
3.2.3 The project started with data gathering. All related
data were reviewed by the project teams of TPAO and Intercomp
in TPAO's Production Department, Research Center, and at the
Batman field site. Data necessary for the study were copied
by Iptercomp and other required data which was not readily
available were recommended for preparation. After the data
- 51 -
collection, the data editing phase started. In the meantime,
necessary laboratory tests were determined and designed together
with Intercomp's engineers in TPAO's Research Center. TPAO's
Research Center conducted various ccre and PVT tests for
the study. Tests for determining the diffusivity of CO, in
Raman and Garzan oils were also conducted by the. TPAO Research
Center. Only a steam flooding and an insitu combustion test
were conducted outside of Turkey by a laboratory in Calgary,
Canada (HYCAL LAB).
3.2.4 The project consisted of the following phases and
was to be completed in 18 months.
A) Geology.
B) Reservoir Engineezing.
a) History Match.
b) Interim Report.
c) Secondary Recovery Studies.
d) romparative EOR Study.
e) Screening EOR Alternatives for Field Applications.
f) Prefeasibility Report Presentation.
At this stage of the project, the Intercomp company was merged
with the Scientific-Software Company and changed its official
name to Scientific Software-Intercomp (SSI). The merge did
not effect TPAO's project.
3.2.5 Participation of TPAO engineers in the project began
with the geological phase and evaluation of the gathered
reservoir and production data. A geologist and a reservoir
engineer worked with SSI on this phase. Two other reservoir
engineers took part in the history matching phase of the
study.
3.2.6 The detailed geological studies were finished and
the geological and petrophysical reports of both Raman and
Garzan fields were forwarded to TPAO for approval in January,
1984. These geological models were the basis of the reservo--
numerical model initilization.
- 52 -
3.2.7 The reservoir engineering phase began with the evaluation
of all production, reservoir and well data. PVT and rock
data were also reevaluated and finalized forms were prepared
for the use in numerical model runs. Upon the investigation
of reservoir characteristics, appropriate numerical models
were selected to study the reservoirs. A conventional black
oil simulator with a feature to study faulted reservoir (BETA
II-F) was selected to study Garzan-B and C reservoirs. For
the Raman Field, the indication of an effective natural
fracture network in the reservoir and areal changes in the
oil properties necessitated a more comprehensive model, KAPPA,
SSI's black oil model with features to simulate naturally
fractured, faulted reservoirs containing oil with spatially
variable properties.
3.2.8 In the history matching phase of the Garzan-B and
C fields simulation study, some problems were encountered
due to the nature of the injectivity data. Injectivity tests
were required by SSI, and the results of these tests were
utilized in redistributing the total injected water rates
to individual wells. Finally the history matching of Garzan
fields was completed and studies for the determination of
the most feasible EOR method applicable to the Garzan fields
were initiated. The test results of both the TPAO's research
Laboratories and HYCAL Laboratory were utilized ir this study.
At the end of the feasibility studies, SSI's basic findings
and recommendations for the Garzan L.elds can be summarized
as follows:
a) The history matched original-oil-in-place figures
for the Garzan-B and C pools are 195.7 MMSTB
and 105.1 MMSTB respectively.
b) A significant reserves extension of the Garzan-B
pool appears to exist along the south flank
primarily in the eastern portion of the pool.
c) Approximately 40 percent of each pool's original-
oil-in-place is contained in the structurally
lowest of the four geological layers. This layer
is also the poorest quality rock relative to
the others.
- 53 -
d) Increasing the pumping capacities of existing
wells and reinstating selected shut-in producers
will accelerate the oil production.
e) The current peripheral waterflood scheme can
be cptimized by increasing fluid rates and voidage
in areas where water has channelled through the
reservoirs and watered out producers.
f) Implementation of an immiscible Dodan gas (CO2)
injection is estimated to provide higher recovery,but
had equal economic benefits compared to water
flooding.
g) Steam and in-situ combustion processes are not
feasible for Garzan.
3.2.9 The simulation of Raman reservoir was conducted
with the "KAPPA" model. KAPPA is a double porosity-permeability,
variable API, faulted black oil simulator. The original-oil-in-
place amount was estimated by volumetric means through
initializations done with a conventional black oil simulator
(BETA II/F). Following the reservoir characterization, the
history match was carried out in 6 segments covering large,
representative and critical areas. In total, 4 three-dimensional
and 2 cross-sectional area history match studies were done with
KAPPA. The subsequent performance sensitivities, the "do nothing"
base case and the optimized base case prediction runs were also
made with KAPPA on selected representative regions of the
reservoir. The reason for studying Raman in different segments
was due to computer limitations. T'HA total field model consisted
of over 6000 (58x26x4) grid blocks. SSI's basic findings and
recommendations for the Raman field can be summarized as
follows:
a) The degree of the development of the fracture system
shows variations in the field.
b) The reservoir production mechanism is controlled by the
presence of fractures and a very active steady state
bottom aquifer. Aquifer is separated from the Mardin
reservoir interval by a dense platformal limestone.
- 54 -
c) Each well interacts with the bottom water aquifer
which lies directly below it in accordance with the
specific collection of factors and reservoir
characteristics in that area.
d) The recovery factor is lower in the northern and eastern
regions than in the southern and southwestern area.
e) The total original oil-in Place in Raman is 611.4 MMSTB.
594.3 MMSTB of the oil is in Mardin, and 17.1 MMSTB
of the oil is in the Garzan interval.
f) Base case predictions estimate a recovery increase
from 43.4 MMSTB at the end of 1984 to 62.8 MMSTB by
the end of 2002, indicating a recovery increase from
7.1 % to 10.3 % overalJ. (Figure 20).
g) Field performance can be improved by optimizing the
current operations by recompleting the wells,
operating them with higher capacity pumps, and by
producing the wells until the economic water cut limit
of 95 % is reached.
h) Operating under optimized conditions, full field
recovery by 2002 can be increased to 78.3 MMSTB,
meaning an increase of 34.9 MMSTB from 1984.
i) In-situ combustion, steamflooding or cyclic steam
stimulation are technically not viable and not
recommended.
j) Cyclic CO2 is not recommended due to its poor recovery.
Continuous CO2 injection can not be recommended
either, since its recovery is less than the water
flood recovery. Fractures reduce the effectiveness
of CO2 injection schemes in Raman.
k! Optimized CO2 (WAG) injection, under optimistic
assumptions, is not sufficiently better thar. the waterflood
to justify the additional expenses of a field-wide scale
project. But in conmarison to the waterflood alternative itexhibits nearly the same recovery potential, if not be'
Therefore, it could,still be tried in the field
the form of a pilot test.
- 55 -
1) Based on abo¶'e conclusions, a field scale pattern
waterflood application, concurrent wlth an
optimization program, is the best a'lternative for
Raman both from the reservoir engineering and economics
point of view.
The study reports were forwarded to TPAO in October
1986.
3.2.10 TPAO actively participated in the project, and at the
end of each study phase reviewed SSI's reports and prepared
and forwarded the points for which TPAO demanded further work.TPAO
began implementingthe field applications of the study results
as soon as they were proposed by SSI and revised by TPAO
management. The applications in the fields can be summarized
as follows:
a) Wells were drilled in the southern flank of Garzan-B
reservoir to search for the reserve extension told
to exist by SSI. The wells drilled in this area
proved additional reserves by being completed
as oil producers.
b) In Garzan, reinstating some shut-in producers was
successful in a few wells. TPAO believes that the
injection water displaced an oil bank towards these
producers which were previously abandoned with high
water cuts.
c) In Garzan, TPAO has began working on the optimization
of waterflooding. Most of the required material has
been purchased and upon installation and recompletion
of the wells, the project is expected to commence in
1989.
d) In Raman, additional infill wells were drilled, and
recompleted as proposed by SSI.
e) Wells were drilled in the northern flank of the 7
field to search for the extension of the oil pc __al
in Garzan Formation.
-56-
f) The water injection plan in Raman field as proposed by SSI
will be considered in the future.
g) The surface equipment and well test procedures were
reviewed both in Rampn and Garzan fields in the light
of SSI's report.
3.2.11 TPAO believes that the "Comparative EOR Study for Raman
and Garzan fields" project served its purpose by giving detailed
descriptions of the reservoirs and their production characteristics,
bringing forward applicable recommendations which later proved
to be economically feasible, reviewing the surface facility
equipment, and pointing out the EOR methods applicable and not
applicable for Raman and Garzan reservoirs.
3.3. THE HAMITABAT GAS FIELD STIMULATION PROJECT
3.3.1 Hamitabat field is the largest gas field in Turkey.
The reservoir contains 450 MMMSCF of recoverable gas with
a specific gravity of 0.59 (Air: 1.0). Production from the
field commenced in December,1976. Since the very low permeability
of the reservcir rock (0.25 md) allows only for very low
productivities, hydraulic fzacturing operations are necessary
in Hamitabat wells.
3.3.z In 1981, the bid documents for the application of
hydraulic fracturing in 6 wells were delivered to 4 companies.
Two companies, Halliburton and Dowell Schlumberger, forwarded
their proposals to TPAO. A committee evaluated the proposals
and awarded the contract to the lowest bidder, Dowell Schlumberger.
The hydraulic fracturing operations were performed on six
Hamitabat wells (H-2, H-7, H-9, H-10, H-l1 and H-13) in October-
November 1981. Fracturing operations were completed successfully,
and because the wells have been prepared before the application,
all the operations were finished 22 days earlier than programmed.
3.3.3 In 1983, a study was performed to determine the optimum
use of Hamitaflat Gas. Two potential purchasers were determined
by this study:
-57-
a) An Ammo:iia Plant
b) A Power Plant (Arbarli)
Since both plants required 50-55 MY.SCF daily gas input for about
15 years, drilling of 12 new wells were required in hanitabat to
meet the daily rates.
3.3.4 After testing the wells fractured in 1981, it was
concluded that Hamitabat reservoir responded well to hydraulic
fracturing and a new RFP was prepared and forwarded to 4
companies for additional fracturing operations. The proposals
were received in February 1984. After the study of the TPAO
evaluation committee and the approval of World Bank, Halliburton
Co. was invited for the contract negotiations in March 1984.
Four TPAO engineers also took port in the design phase of the
study. Two operation engineers contributed to studies in the
Halliburton Co. Operation Center, Duncan OK, and oric reservoir
and one workover engineer worked in the Halliburton Co. Design
Center in Netherlands for the design of the Hamitabat fracturing
operations. Meanwhile TPAO tesLed and recompleted the wells to
be fractured. 16 Hamitabat wells and 2 other wells (Umurca-05,
Yesilgbl-l) in the nearby fields with similar reservoir
characteristics were fractured by Halliburton. 11 Hamitabat
wells were fractured at one stage (H-1, H-5, H-12, H-14, H-18,
H-19, H-20, H-22, H-23, H-24 and H-30). 5 Hamitabat wells
(H-15, H-25, H-26, H-27 and H-29) were fractured at two stages
by the use of ball sealers in one well and sand in two wells
as diverting agents. Coil tubing unit was used in 11 wells for
cleaning the remaininq sand from the wellbore. Temperature logs
weLe run in some of the fractured Hamitahat wells to compare
the designed fracture heights with the actual created fractured
heights. After the fracturing operations, wells were tested to
determine the deliverabilities.
3.3.5 In 1986, the last hydraulic fracturing project was
initiated for five new wells drilled in Hamitabat, (H-17/A,
H-28, H-32, H-33, H-34) and three wells in Umurca (U-02, U-04,
U-07). RFP's were prepared and forwarded to four companies,
and from the two companies (Halliburton and Dowell Schlumberger)
- 58 -
who submitted proposals, Dowell's proposal was selected by the
TPAO Evaluation Committee.The contract was signed in 1986. After
discussionswith the TPAO Staff, Dowell prepared preliminary
fracturing designsfor each well. The operations were ccrpleted
in 1987. Each well was cleaned up with coiled tubii:g after the
operation, and temperature logs were reccrd&d to determine the
fracture heights. Deliverability tests were also conducted on
all of the fractured wells.
3.3.6 Overall, the fracturing operations in Hamitabat and
Umurca fields were successful. Testing of the Hamitabat wells
indicated a considerable deliverability increase due to
hydraulic fracturing.
3.4 THE MANAGEMENT STUDY
3.4.1 In order to provide TPAO with assistance for improving
its operational productivity and its management organization,
it was decided to prepare a specific management study. For this
purpose, a contract was signed with Arthur D.Little International
Inc. (ADL) in 1983. TPAO 's senior management wished ADL to
undertake a diagnostic management study aiming at upgrading the
ccrporation's performance, and establishing the political targets
in the areas of internal reporting systems, management control,
warehousing, accounting, financial planning and administration.
A final report which was presented to the senior management of
TPAO identified the main requirements fcr the corporation to
carry out its functions in a more rational and functional way
in the light of management techniques and administrative
sciences.
3.4.2 In 1985, TPAO has signed a second contract with ADL
for the execution of diagnostic management study which is not
included under the extent of LOAN 1917 TU. By this study, TPAO
required the establishment of an efficient computer-based cost
control system in order to receive reliable and timely cost
data for management decision making and obtain a clear
- 59 -
dt scription *f each unonixt d Dcb N.thir, the corpcirciticr. tocgether
,.ith the quaI I ficat cns , skills drcd : i r . ( C t qu, recd of thlose
,I.o ;:,.d tc. f I1 t .*n; tc form ; t 4-s 'or jcb (jrzdi:cj, for
>flnn ir.g c,f hurai :* , I Xt Cc< !r (! . SC-: (.', c bosis f'or PEIy
struc tui e. ADI . i t (. th.: F tudy :r. 19V-. A ccrmputt rizLd cost
c- ntrc1 study was .'-so c(c7 I -tL'd ty. ADl In 1 987.
- 60 -
A N N E X E S
- 61-
ANNEX 1
CATEGORIES OF THE APPRAISALS FOR THE PROCEEDS OF LOAN 1917-TU
Cricirc r FinalApraisal Aplras
'a____ cry _____ USD USD USD
i-A Bati Farman Field 6 600 0G0 6 600 000 7 600 OOC(Drilliri(,, worikover andlaboratory equipment)
1-B Raman Field 5 400 000 5 400 000 5 400 OOC(Drilling and workover eq.)
1-C Haritabat Field(Fracturing) 2 200 000 2 200 000 6 400 000
2 Bati Raman Field 15 600 000 25 600 000 21 400 000(Dodan and Bati R~amansurface facilities)
3 Bati Raman Field 6 000 000 3 500 000 3 500 000(Dodan-B.Raman pipeline)
4 Bati Raman Field 5 600 000 5 600 000 12 600 000(Consultant services and =training)
5 Bati Raman Field 2 600 000 2 600 000 1 600 000(Chemicals and otherservices)
6 Refunding of First Loan 2 500 000 2 077 511 2 077 511
7 Contincjency 15 500 000 8 422 489 1 422 481
TOTAL 62 000 000 62 000 000 62 000 000
CATEGORIES OF THE PROJECT DISBURSEMENT OF LOAN 1917 TU
CATEGORY ALLOCATION DISAMOUNT REMAINING _ PROJECT
1-A 7 600 000 6 693 518.01 906 481.99 Bati Raman-Drillinq, aorkdvcr ard
laboratory equipImen:t
1-B 5 400 000 3 026 962.27 2 373 037.73 Raman-Drilling and %;orI},vvr equipnweit
1-C 6 400 000 6 282 660.92 117 339.08 llamitabat-Fracturinig Fr( J* ct
2 21 400 000 20 718 590.35 681 409.65 Bati Raman-Surfacc Facilities
3 3 500 000 3 160 494.75 339 505.25 Bati Ranmaii-Dodan-B.Raman piutipintv
4 12 600 000 10 862 631.09 1 737 368.91 Bati E:aman-Enqincerrii(ij,training,insp(ctiet .
and vendor services; the wanagerrt,ittstudy
5 1 600 000 2 017 086.26 (417 086.26) Bati Raman-Chemicals
6 2 077 511 2 077 528.35 (0.35) Bati Raman-Bati Pan;a:i [E.odPr fields
feasibility study.
7 1 422 489 - 1 422 472.00 Project-Contingericy
TOTAL 62 000 000 54 839 472 7 160 528.00
Report for period cnded March 3_1985
PROCUREMENT SCHEDULE OF ORDERS AND DELIVERIES OF MAIN ITEMS OF EQUIPMENT FOR LOAN 1917 TU.
Date of Bid Date of Bid Date of
Description of Item Invitation Opening Order Name Supplier Contract Amount
Compression System Dec.,30,80 March 5,81 Aug.20,81 Cooper Energy Services, USA 1 970 573.48 US[,
Line-Pipe(Item 1,2) Feb.9,1981 March 27,81 July 1,81 Vallourec lit., FRANCE .0 107 433.00 FT
Line-Pipe (Item 3) Oct.1,81 Vallourec Int., FRANCt 1 953 493.00 FE'
Line-Pipe Coating Sept.2,81 Oct.2,81 Oct.13,81 Vallourec Int., FRANCE 3 114 837.00 tF
Workover Rigs April 12,80 July 3,80 March 11,81 IDECO, USA 901 224.00 USL'
Heater, Seperators July 23,80 Sept.11,80 Feb.2,81 NATCO, FRANCE : o39. I4(f.00 tIF
Launcers and Receivers Oct.6,81 Dec.4,81 Jan.18,82 GH Progressive Metals, IUSA 32 118.00 USD U
Pipe Line Valves Sept.9,81 Dec.4,81 Feb.2,82 Saut Du Tarn-FRANCE 184 262. 00 t'F
Actuators Sept.28,81 Dec.4,81 Feb.2,82 Shafer Valve Co., USA 70 600.00 USD
Field Coating Material Sept.19,81 Dec.4,81 Jan.27,82 Plicoflex, USA 13 406.5 USD
Pipeline Facility Sept 28,81 Dec.4,81 Jan.20,82 Interservice Trading, IHOL.LAND b3 It74.33 PEl
Piping
Pipeline Fittings Sept.28,81 Dec.4,81 Jan.21,82 Phoceene, FRANCE 121 207.0 VI
and Flanges
Pipeline Bends Sept.28,81 Nov.20,81 - Phoceene, FRANCE
Small Valves Sept.28,81 Nov.20,81 - Phoceene, FRAtCE tb 320.00 [t
Scraper Passage Sept.28,81 Nov.20,81 Feb.22,82 TD Williamson, USA 11 7b4.44 USV
Indicator
Meterin(J and PressureControl Skid Nov.4,81 Dec.18,82 March 3,82 Midcon, USA 11R 355.00 USI)
Test Manifolds Nov.4,81 Dec.18,82 Feb.17,82 Anthonic, UK 34 549.00 E
Corrosion Inhibitors March 10,82 Champion Chemicals, USA. 15 309.Of0 USD j
External Coating W
Material March 3,82 Phicoflex, USA o 26.S.50 USD
Date of Bid Date of Bid Date ofDescription of Item Invitation Opening Order Name Supplier __ __ Conti.itt Amount
Tubings and RelatedParts-I Jan.11,81 March.30,82 June 22,82 TPS Technitube, GET, - 184 740.00 D*M
Tubing and RelatedParts-II Jan.11,81 March 30,82 June 22,82 SUMITOMO, JAPAN 634 884.32 USC
Pipeline Construction Jan.19,82 March 15,82 June 14,82 ATTILA DOAN, TURKEY 3C0 000 000.00 TL
Pipeline Inspection March,8,82 April 9,82 June 22,82 'iEKFEN, TURKEY ';' :;35.00 USD
Selexol System Oct.20,81 Jan.8,82 July 26,82 ALARKO, T'URKEY ' 760 103.00 LUSI
Dehydration System Oct.22,81 Jan.8,82 July 9,82 CE-NATCO, FRANCE 7 104 1'5.00 EtF
Motor Control Center March 8,82 May 7,82 July 16,82 FTMA*, TUPKEY 123 734.05 USLI
Separator Systems Feb.8,82 April 9,82 Sept.1,82 ALARKO, TURKEY , (12 f54.0( (I t"
Off-Gas Disposal March 29,82 May 28,82 Sept.3,82 JOHNZ1iN4, FRANCE I 810 200.00 FFSystem
Christmass Tree jan 20,82 April 7,82 July 28,82 FMC, FRANCE 1 .15 000.49 USLD
Production Packers Feb.12,82 April 20,82 July 30,82 BAKIE?, :1 ('11.90 USI1
Sucker Rods-I Feb.12,82 April 26,82 Aug.3,82 DRILCON, ENGLAND 2':6 8.(.00 ('SLD
Sucker Rods-2 Feb.12,82 April 26,82 Aug.22,82 VEW, AUSTRIA bb2 Wt,:.60 A
Electric Motors March 8,82 May 7,82 Aug.24,82 AEG, Telefunken, GERMANY 379 012.00 [M
Transformer March 8,82 May 7,82 July 17,82 AEG-Eti, TURKEY 2 040 000.00 TL
Generator March 8,82 May 7,82 Sept.12,82 Siemens-AG, GERMANY 97 190.00 DM
Instrument Air System April 19,82 Jan 7,82 Nov.8,82 Demta-TURKEY 16b v40.00 USD
Manifolds Feb.25,82 May 3,82 Oct.8,82 CE-NATCO-FRANCE 11 bO9 450.00 IF
Central Alarm System May.17,82 July 16,82 Oct.6,82 Technical Products, USA 77 039.00 USD
Chemical InjectionPackage May. 6 ,8 2 July 7,82 Oilcovery Eng. 58 508.00 USD -
Valves March 24,82 May 26,82 Oct.21,82 G.De Boer. - HOLLAND 163 236.00 DE a
Flan(e and Fittings March 24,82 May 26,82 Oct.21,82 Sella, ENGL,,II - A * ( I
Date of Bid Date of Bid Date ofDescription of Item Invitation Opening Order Name Supp1ier Contract Amount
Gaseous Pumps June 28,82 Sept.20,82 Jan.12,82 Uss Oil Supply, USA 313 097.00 LISD
Field Pipes (Steel) Oct.4,82 Dec.15,82 March 7,83 TPS Technitube, GERMANY 404 321.35 DM
Steam Generation March 29,82 June 4,82 March 3,83 Alarko, TURKEY 756 465.00 USD
Field Pipes (Fiber) Oct.4,82 Dec.5,82 May 9,83 Trouvav Cauvi:i, FRANCE 1 154 321.10 USD
Surface Safety Valves March 21,83 May 25,83 Aug.15,83 Armco, USA 110 31 1.ue. t: I
Off-Skid Ins. April 7,83 June 3,83 August 8,83 Incotes, IN-1I.AND 65 747.65 £
Bulk Piping April 7,83 June 3,83 Sfpt .26,83 Van Leeuwen, IIOL.LAND) 981 993.20 DFI.
Fiber PipetsInsulation August 20,83 Sept.14,83 Nov.1,83 Tekiz, TURKEY .93 688.00 USD
Manifold Spares - - Oct.11,83 CE Natco, France 983 180.00 11
Bulk Piping - II Nov.5,83 Dec.5,83 Dec.16,83 Van Leeuwen, Holland 251 071.00 DFL
Electrical Wires June 27,83 Sept.8,83 Nov.8,83 Turk Siemens, TURKFEY :-!0 ,48.00 USD
Heat Tracing Mat. - - Feb.5,84 Thermon, USA 21 34 t .(S D-L
Instrument Cable - -- Dec.6,84 Anixter, USA 3 977.00 UISD
Fiberglass Vent Pipe - - March 5,84 Trouway Cauvin, F!i,:NCi *0 441.00 USD
Filed Insulation - - April 4,84 Tek-tz, TURKEY i' U,8.00 USn
Bulk-Piping-III - - May 29,84 Van Leeuwen, 1101P1.,kN1 348 236.74 DEl.
Construction BidPackage Dec.14,83 Feb.17,84 May 7,84 Guri!, TURKEY 541 ,89 134.00 TL
Stainless Steel Pilj April 22,84 Van Lecuweni, HOLLAND 407 530.47 DEI.Sleexol Solvent - - NortAn,, UK 2 541 000.00 DM f
Triethylene Glycol June, 84 July 5,84 Aug.21,84 Wilhelm Sclhroder 215 957.00 nM W
Corrosion Inhibitor - - Oct.30,84 Champion - USA 6 441.bU U: tu
Corrosion Inhibitor - - Oct.30,84 Nalco, ITALY I j i',. I.0 Lt
Demulsifier - - Oct.30,84 Petrolite, UK 4 9C(.Ci
Defoamer - - Oct.30,84 Champion, USA 2 65b.50 USD
Date of Bid Date of Bid Date of
Descri)tion of Item Invitation Opening_____ Order Name SuMpplitr__ Contract Amount
Corrosion Inhibitor - - Oct.30,84 Nalco, ITALY 7 425 500.06i lit
Se-lexol Antifoam - - Nov.7,84 Union Carbide, lISA 500.0on L.-I
Compresscr Lub. Oil - - Dec.14,84 CES Associate, USA 56 685.0( U:;l
Antitoam Ing. System - - Dec.17,84 Williams, USA 2 08t .00 LSI)
Fire and Safety System - - Dec.16,84 MSA, USA _7 970.05 UISD
Dehydration Spares - - Jan.10,85 Wi 11 iawis Pi- L, *SA 5b 000.00 USD
Generator Spares - - Nov.30,84 Sitmb :s, , AG -6 3o00.00 oo M
MCC Additional Parts - - Nov.8,84 Siemer ;, Ac . . If'
hl'tiko Spares - - April 9,85 Germotec le 08E1 .1I USL
Field Pipes (Fiber) - Sep.1r,3 Trouvay Cauvir,, FRANCE b .t4 tl'SL
ftj
- 67 -
F I G U R E S
(/W//+7|-. /t l2 | 2 205 / I-
159g/'- - 20
550~~~
¶9 I - I, 42//j~~ Io4~J -0 j
~~~~~~~, G5 INECIN E>
--- PtLO 19A 98
7 0~~~~~~~~~~~~~~~~~~~~~
_ . -~~~~~~~~~~~~~~~~~~~~~~~~~~~~6
100 0
3 IS~~349
,9WATER INJECT ION WELL 5 7 T Z Z
--PILOT AREA1986
The Batt Roman Field EOR Pilot Project Application
Dodan Plant Batt Raman Field1700 psia 20 MMSCFD initlally
55MMSCFD future pipeline,--1 \ ~10-in pem c2 i80.5km 1500 Porduction
Compressor of ter-cooder Pen Qporatort
690 psia venterCO2 evaporator 55 MMSCF- -tmoshere Test
capacity CO epaaorot
Cyclic 7 StoreProduction 0 lyCOt ~~~~~~~~Injection tan 4000 BPD
separotoro( rAegeYnCe°rator 20 MMSCVF D -
evaporator IHOQ W
Dehydration System
oatmophere L To BatmonTest sepaator) Injection Production Rof inery
. _ / Selexol X \ incinerator Mode Mode
_ system __|Project Area
r 1 60 MMSCFD ---- H2S/CO2 (33 Wells)Typicol Welthead capacity(12 initially)800- 950 psia G
CS
Simplified Flow Diagram of The Pilot Project
BATI RAMAN - CO? PROJECT
log0- .
~40
Wm am
3. "L I .1Wm S I I I
am~~~e
100
-X0
m VI~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~,
I * 11 A k J J A 3 O 1 D J f X A X J J A 3 O N D J P X A X J J A 8 O ,166 9 1967 19tS
TiRPViYF PFTRnI I ccl A ( I.IFTiM C.RI IR: I RAr(ANI le.1 Ril ri RI FM MFRKF71
9 - 71- friGutt 4
BATI RAMAN - CO2 PROJECTa~~~~~~~'LOOO ~~PRODUCTIlON llI9WTOl A13OUT REGIONS 1
A.Pl~~~~~~~~~~~~~~~~~~~~~.
ad W Y~~~~~~~~~~~~~
C-,
2500 '3TP2 , 0
2000 , v 8.0
1500-- 6 |.0 3
I~~~~~)I
100-O l 0 4.0
ooot
a URKII P T I I I II I. UE IM GUUB 6AKNI I BiLG i EREi . -
L500 - TI20.0
1300 8.0 C-~~~~~~~~~~~~~~~~ - L~~~~~6.0
CD)
100- 4.0 B-
b 300- 2. 0 ~ ~ ~ .
0le. .1. . . . . .9. .
TURKIYE PETROLLERI A.0 URETIM GURUBU BA~KANLICI . BILGi i$LEM MERKEZI_______
- 72 - FIGURE 5
BATI RAMAN - CO. PROJECrPRODUCTION & INJECT[ON HISTORY OF THE F[ELD
ENTIRE FIELD i,
39
Cl
I n aooo- _ _ ~~~~~~~~~~~~~~~34 ^IO1000- -32 o o
0~r_ 305000- Loa..- 0
sTEST FEELD
25000 - .4t
-4000 JEST FIELD - ma
In ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ 0
3000 so I'
, 2000 - . .40
I ooo- - 20 -
2. 500~ , /52 J 2 000 4 Y l
P500G - W Ia- 03
a ~~~~~~~~~~~~0 0i r u A v i A a 0 W D i p n A x i i A 8 0 1 D i r x A u i i 8 0~~~~~S. S
01500 9~~~~~~~~~~18 ls
C.)T W EPTOLE!A0 OEI UUB AKNI,l-RiG $E EKZ
A'TER CS 2
TURKIYE PETROLXERI A.0. -^RETIM GRUBU BA5KANLI(,l - BILGi 15LEM MERKEZII .
1oUZ"0 '. S1
TEARS f
____________________ TURKIYE PErROLLERI A 0 - URETiM GRUBU BA5KANLIGI BiLGI ISLEM MERKEZI ______________
NUMBER OF OPERATING WELLo * * 8 t!t °o So t So So o CUMULATIVE WATER (MSTB)
* ,~ , z , , ,CUMULATIVE OIL (MSTB)
RATE (STB/WELL/DAY)
tz
-I~~~~~~~~~~~1
00 IIxS
a~ ~ ~~~~~~
C:
C)
-CA
I-
( ) Lns 83LYJi ~~(6L1U;* -0.iOL3.ACrO'd -J .10 ;O
j L uinoDI
I_~ ~ ~ I
BATI RAMAN -CO INJECTION EFFICIENCY
'300
~24
0 a.
0.
.J~~~~~~~~~~~~~~~~~~~~~~~~~ Is
0T tJ VV WJ A9 1D FV Wi A 3 0 W D J F MA WJ J A 30
TLJRK iYF PFTROI I FRI AO URETIM GRUBLI BASKANLItIl - BiLGi ISLEM MERKEZI____________
BATI RAMAN - C PROJECT
INJECTION HISTORY OF WELL # 10930 ~~~~~~~~~~~~~~~~~~~~~~~~~~~1000
Z o72- - I .00
o 0A I 300 ,,
o o
D J F JFUAIJJASON
456 L10 0 ¶I"' 000
32-461906 4I f00
t100
'~~ 4.. ....... 400
D J F X & M J J A S 0 N .
Tl IRKiYF PFTR)I I FPI AO liRFTiM G.RIM1I RACKANI 1t. - Ril C.i NisFM MFRKF7i
9 - 77 f IGURE 10
BATI RAMAN - CO. PROJECTa R PRODUCTION HISTORY OF WBLL 182CQ' a, l
E- 3 i
3 -- ! e ri,S I X k ,, , , _, , ' ^ , 1 ' I~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~
C . . . . . .. . . . . .a0-
- 00-
2 0.0- F so.o- '-
o '30.0-t200
250-
I !- 1* 0
o
50
MAR PI UMAT JUN JUL AUG 33? OCT lOV DRC JAN 7RV HAl UPI AT JUN JUL gO0 ORP OCT
VI
! ~~~TURKiYE PETROLLERi A.O. URETiM GURUBU BA$KANLIGI - BiLGi I$LEM EKZ
TPRO PRODUCTION GROUPSTATUS OF B.RAMRN WESTERN AREA WELLS
(l5-cct-1988)4190000- . LEGEND 1
. - 02 LnJtn*-f'"oduct. .vr,- tdrwdu I 3TP1 3TP2 API
o - I,,d.iLI,pr'* - 60- h.t5--gIr4wt
41at1000 *-°° h t L,
*5 a A* , * Ut 5 a~~~~~~~~~~~~~~~~~l
*9 0 9 i
EL 4181000 LT * LI, y * /79 773 /7*
t 1s 215 1 11" L Iy 11e' IIh' 1 t S r-215 9e 113
a 101X 41ffAM in~~~~~ &4 .1 a 7,
9 9~~~~~~~~~V
4 1~~~~~~~~~N'19
13 ,9
4C186000- S1 U
68000 6810 0SO= 6 60600 S67000 aCY-COORT INRUTE
L TURKiYE PETROLLERI A.0. - URETIM GRUBU BA5KANLIkI - BiLGi i$LEM MERKEZI
PRODUCED OIL DISTRIBUTION OF B.RAMAN WESTERN AREA WELLS01B-sp-1986 TO 19-oct-1966
550
so~~~~~~~~~~~~~~~~~~~~~~~~~
I TIlrK jrF PFTFnl P cKI ^ n . IlRFTild fiKIIPII RARKANI 1<1 * Pil Gi IS FM MFKKFZI ._ _-'
I ~~~~~~~~~~~~TI IAKiYF PF TR r)I I 1D91 AOC - IJRFTiM GRI IRI I RA fK ANI I e.i - Ril GI iqI FM MFRKFZI _____
PRESSURE DISTR[BUTION OF B.RAMAN WESTERN AREA WELLS01-mug---190 TO 13-oat-L1968
a"0|
useo
TIIRViYF PF TR -U .rPi AO URF TIM CR I IRI IRAcKANI I r I Ril(-,! ISIFM MERKEZi
TIIRViYF PrTRF'I, fDt A 0 - lJRFTiM (.R1IRIS RACK~ANI 1~ R1- i Gi ISI FM MERKEZi - ________-
GOR DISTRIBUTION OF B.RAMAN WESTERN AREA WELLS01-*op-1988 TO 19-oct-1988
35 1 D-5
tio I
to
5~~~~~~~~~~~~~~~~~~~~~~~~~~~~~
0~~~~~~~~~~~~~~~~~~~~~~~~~~~~~
TioVII YVF Pr7TOC~ mN;ri An( I R5:Tim raiti PAI W ~ACA KII It. it in i K14 MFRvr-7i
500- mm~~~~~--g0
450- 0 -oil450 * -Gas -- - 9070 -~ -
400 -- - 9 00
z IO300- 3 - 0 40 5 5 00-
o ~~~~~~~~~~~~~~~~~0 250 - 4 1
0~~~~~~~~~~~~~~~~~~~~~~~~~~~~0(
200---00
_ __ . TURK;YF PFTROI | FI I A a RTMGUUBSALG IG SE EKZ
-j ~~~~~~~I400
ISO 3~~~~~~~~~~~~~~~~~~~~~~~~~~~~~000
100 ---- A 200
0 rr -40~0- n -
0 50 100 150 200 250 300 350 400 450 500 550 600 650 700 750 800 R50 900 950 1000
TIME , DAYS
FIGURE 15 PRODUCTION TIME IN "HUFF Sk PUFF APPLICATION
________ TURK lYF PFTRflI I FRI A.0. - URETIM GRUBU BASKANLI& - BILGI IMLM MERKEZI
200- -2000
0fi Oil Production / r GAS
180 Gas Productioa. e _ _ __ . _ _ ISO
160- -
16-X__o _ ___ 1 __ ._ _ _. -10
0. 140- _.._ ___ __ ___ __ -1400 IL
0 120 _ ---- - - _ - - - - -1200 . I
o n __ __W __ __ ___ L- -' L
o-........_.I..- 1z
0
00 100 20 ---300 400 50 -70 -900 1OI a~~~~~I
40- - -j-00
20-~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~
I I0
0 100 200 300 400 500 600 700 800 900 '000 1100 1200 300 1400 I0
TIME, DAYS
FIGURE IC GAS FLOODING PERFORMANCE OF PRODUCTION WELLS A
Ti IRV IYF PFTarrl I rol A £ I IRFTIM (-RI IRI I RfA-KANA It',I - Ril Gi ISLEM MERKEZI ___ _ I
500-
350 - -
450 -Rm___
400 -
_ _
0
*200
__
50
0
a f . FR."Us E : t XIM DAYF G- -1I 7 G S I
XMATRIX A
T. -KY- -IA- FO 100 200 300 400 500 600 700 800 900 1000 1100 1200 1300 1400 I50
FIGURE 17 GAS SOLU81LITY IN OIL IN MATRIXES AND FRACTURES -
TllRKiYF PETR)I I FRI A 0. URETiM GRUBU BASKANLIGI - BiLGi ISLEM MERKEZ; __________ _ _ I
2 [ odeol I l i I X 2000 Dzo 1 o-eto _____ ___- 10S Oil Ptoductioe' _ --- 800
180- A Gas Prodoction
9620- ___ _ ____ _ _ _ __ __ ___ _ _____ __ __ ___ _ ____ _ - -960
O 100 ~ _ _ l _ _ r- _ ~ 10 00160-~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~La ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~~~~~~~~~~~~~~~~~~~~~~~~'
O 920 _ ___ ____ __ __*_ _L_ _~S__ _ ___
O-~~~~O 1400 301040 0 00 80 gO l 10 20 10 40 I00 U
220
o 900- LII U
I. Tl_ IR iYF__P I ___ A_ --80 I RTMCR R AKN o1-RlG SE EKZ
80 I
am an') _ _ _ ____ -60060- C
40- - I- _400_ _
o 900 200 300 400 5~00 600 700 800 900 9000 9900 12'00 9300 1400 9500
TIME, DAYS
FIGURE 98 :THE GAS FLOODING PERFORMANCE OF PRODUCTION WELLS WITH LOW INJECTION RATES
T)IRKIYF PFTPC%l' rol A 0 - IIRFTIM C.,RIIRIlI RASI(ANI Itli - Ru i(, ISLEM MERKEZI ______
-~~~~~b 'S 43 -t--m 4 - "
0 6I
275 Be~ ~ ~ ~
too ~ ~ 6 ~~~2Z~I4D is- ~~~~410- -»// v < 1 u -LE G ENT
WATER INJECTION WELL < °8* *PRODUCTION WELL\
_* ABANDONED WELL :
O ORY WELL I* NEW WELL LOCATION 1989
The Bat, Ramon Flod EOR Project Expanslon
50.050 s
RAMANo~ 4
p240,M 00
0
30.m~~~~~~mrzMm;inosm
Ej 505 S.
YEARS
isa MesOe-
0 ~ 7 70
81 ~~~~~~~~~~~~~~~~~~~~~~~~~~~~~00
so D mm 30
0 a 0~~~~~~~~~~~~~~~~~~~~~~~~~~~
TfIIRKiYF PFTPfl I roi A Cn I IRFTIM r.Rl mFi I RAWIANI li(tf Rul ri 5IV FM MFRtKE71 - _________
- 88 -
Part III
1. RELATED BANK LOANS
Year ofLoan Title Purpose ApOroval Status Comments
a. Loan 1916-TU (a) To assist TPAO in 1980 Completed in This was thePetroleum the exploration of Dec. 1985 Bank's first loanExploration subtle trapping to the TurkishProject structures in areas of Petroleum Sub-
SE Turkey; (b) to finance sector. A PCRTPAO's exploration efforts for the projectin the Hakkari area; and was sent to OED(c) to help finance the on April 1, 1988.first phase of the Thraceexploration program.
b. Loan 2327-TU To assess the hydro 1983 Completed in The project hadThrace Gas carbon potential of TPAOs June 1987 mixed results.Exploration licenses in the Thrace Four rigs ofProject basin; and (b) to strengthen TPAO were reha-
TFAO's ability to design and belitated andimplement an integrated added to itsbasin-oriented exploration fleet. Actualprogram. seismic coverage
was much morethan the appraisalestimate (42% or750 km more in theThrace basin andan additional2,000 km outsidethe Thrace basin).Eleven deep wellswere also drilledas planned. But nosignificant hydro-carbon reserveswere discovered.
- 89 -
2. PEQJECT TIMETABLE
Date Date ateLtim Planned Revised Actual
- Identification Early 1978- Preparation October 1979- Preappraisal Nov. 4-20, 1979- Appraisal Jan. 29-Feb.21,1980- Post-Appraisal June 1-7, 1980- Loan Negotiations Sept. 1980- Board 'tpproval Nov. 18. 1980- Loan Signature Nov. 24 1980- Loan Effectiveness March 1981 June 16, 1981- Loan Closing Dec. 31, 1984 Dec. 31, 1987- Project Completion June 30. 1984 June 30. 1987
Comments
2.01 The main issues at the Issues Paper stage of appraisal were asfollows:
(a) The lank considered that TPAO should carry out the C02 injectiontest only in the western section of the reservoir and that TPAOshould initiate an expanded test program in the central section onlyafter full consultation with the Bank,
(b) Separation of TPAO's domestic oil operations from its imported oiloperations with a view to both strengthening the management ofdomestic oil exploration and development, and isolating the financesof the domestic oil operations from the vicissitudes of imported oiloperatiors;
(c) GOT would carry out a plan of action, acceptable to the Bank, foroffsetting or eliminating the foreign exchange losses of TPAOincurred from January 1, 1981 due to its outstanding foreign debtsfrom importing petroleum and petroleum pLoducts;
(d) TPAO would have a long-term debt equity ratio of at least 50:50 and adebt service coverage ratio of at least 2.0;
(e) In the event TPAO's accounts receivable exceeded two months of sales,COT would provide funds, or cause funds to be provided, to TPAO onterms not disadvantageous to TPAO;
(f) In the event of a shortfall in TPAO's internal cash generation, GOTwould provide the difference in the form of equity; and
(g) $10 million ove, and above the proposed lcan of $50 million would bemet by the Bank in the event potential cofinancing could not besecured in time for the project's implementation schedule.
- 90 -
2.02 The following changes were made as a result of negotiations:
(a) In view of an increase in the foreign exchange costs of the projectand the inability to secure timely cofinancing, t,,a loan amount wasincreased from $50 million to $62 million to cover the entire foreignexchange costs of the project;
(b) The loan terms were changed to standard country terms, namely, forseventeen years including four years of gr*ce;
(c) GOT presented, and the Bank accepted, a plan for eliminating theforeign exchange losses of TPAO on its outstanding foreign debtassociated with the imports of crude and petroleum products. TPAOalso concluded satisfactory arrangements with the Turkish ElectricityAuthority for obtaining timely electricity supply at Dodan gasf ~ld. These had been proposed as loan effectiveness conditions andwere deleted since they were no longer necessary; and
(d) TPAO furnished logging and coring data for three wells from theThrace gas fiele. This had been earlier proposed by the Bank as adisbursement condition and was now accepted as fulfilled.
2.03 The execution of a satisfactory Subsidiary Loan Agreement between GOTand TPAO was e condition of loan effectiveness.
3. Loan Disaurbsements
Cumulative Estimated and Actual Disbursements(US$ Millions)
1981 1982 2Iq. 1984 29 1986 1987 198 122
Appraisal Estimate 14.5 54.5 59.5 62.0 - - - - -
,*tual 2.08 9.06 20.87 34.61 44.72 49.68 52.48 54.51 54.61Actual as % of Estimate 14.3 16.6 35.1 55.8 72.1 80.1 84.7 87.9 88.1
Date of Final Disbursement July 18, 1988
NOTE: Poth the appraisal estimate and actuals include adjustments of theengineering loan of US$2.5 million.
A time line presentation of the appraisal estimate and actuals ofdisbursements is given in the attachment.
4. Prolect's Oblectives and Description
4.01 The project had three main objectives: (a) to increase Turkey'scrude oil production in the short term by developing the newly discovered oilreserves in the Raman oil field; (b) to expand Turkey's recoverable reservesbase through the application of new enhanced oil recovery techniques and toenhance its medium-term petroleum production capacity; and (c) to evaluate thegas reserves and production potential of the newly discovered Hamitabat gasfield.
- 91 -
5 . Pro 1ect Costs and Financina
A. PROJECT COSTS (USS MILLU.JS)
APPPRAISAL ESTIMATE ACTUALLgeal Fore1on TaA1 Lgca Foreign Ita1
Bati Raman Field Test
1.1 Wells drilling and workover 6.6 6.6 13.2 7.0 4.5 11.5
1.2 Surface fields facilities 7.7 15.2 22.3 4.5 22.5 27.0
1.3 Gas pipeline 3.7 6.0 9.7 1.5 3.2 4.7
1.' Prefeasibility, engineering 1/ 0.5 2.5 3.0 0.5 2.1 2.6
1., Design, supervision and training 1.0 2.5 3.5 0.5 8.0 8.5
1.6 Chemicals, monitoring and evaluation 2.L2 -.2. 6 4805 3 4 4Subtotal 212 7 I3 57.1 14A5 44Al 2.5z
Raman Field Develooment
2.1 Wells drilling and completion andgeneral drilling equipment 4.8 5.4 10.2 8.0 1.2 9.2
2.2 Water disposal and productionfacilities 1.0 0.4 1.4 - 1.0 1.0
2.3 Reservoir study II 0.7 0 9 - 1.4 1.4
Subtotal 6 i Li 11.6
Thrace (Hamitabat) Gas Field3.1 Wells stimulatior. and equipment 0.7 2.2 2.9 0.5 6.2 6.7
3.2 Gas reserves and utilitization study 0 1 04 0 -
Subtotal Q. 83 Q364 6.7
Manaaement Study and Training 1 0 1505 06 11
Subtotal 29 0 45i5 74 5 0 1.1
Physical Contingency 5.5 8.9 14.4 _ _ -
Price Contingency 5 5 76 1 -1 -
TOTAL 40 ° 2 235 5 781
1/ This i.em was financed under the $2.5 million engineering loan (S-13-TU).
- 92 -
Comments
The final total project cost is US$78.1 million equivalent with aforeign exchange component of US$54.6 million. The cost undeirun is about23.4 percent in total costs (about 11.9 percent in foreign costs and 41.3percent in local costs). The reasons for the variances in the costs ofindividual comuponents are given below:
(a) In the Bati Raman EOR component, cost savings were made in drillingand workover by maximising the use of existing equipment asid materialin TPAO's warehouse, and in the Dodan/Bati Raman gas pipeline byusing local contractors for construction instead of foreigncoatractors as originally planne'. The local cost expressed in USdollars was also less than estimated because of the devaluation ofthe Turkish Lira vis-a-vis the US dollar during the project period(from TL7O/US$ in 1980 to TL1700/US$ in 1988). The increase in costsof consultancy servicej was caused mainly by a delay of over threeyears in project implementation and changes in the scope of theconsultants' work as required by the project needs;
(b) In the Raman conrponent, cost savings were made in drilling only 17wells instead of the planned 18 wells and utilizing the equipment andmaterial available with TPAO. The increase in the costs ofConsultancy Services was due to increase in the scope of theconsultants studies in 1983 to include both R.aman and Garzanfields; and
(c) The increase in stimulation coats in the Hamitabat Gas fields was dueto the increase in the stimulation program from tha original 6 wellsto 24 wells. Gas reserves and evaluation studies were made in-houseby TPAO resulting in cost savings of about US$0.5 million.
B. PROJECT FINANCING
PlannedSource (Loan Agreement) Final Comments
(US$M) (US$M)
IBRD 62.0 54.61 The final cost financed by the Bank(entire foreign cost) was only88.1X of the appraisal estimate. Theunutilized sum of $7.39 million wascancelled on August 23, 1988.
Other ExternalSources Nil Nil
Domestic 40.0 23.50
102.0 7S.l1 The actual local costs financed byTPAO were only 58.8% of theappraisal estimate.
- 93 -
6. Prolect Results
A. DIRECT BENZFITS
Appraisal Esti-ated at Estimated at,Indicators timate- ClgainF Date Full DeveloDment
Bati RamanExtra Oil Four million 5.12 million 9.86 millionProduction barrels in 3 yrs barrels in 3 yrR barrels in 3 yrs
Raman Oil Field
Extra Oil 3.9 million 1.5 million 2.9 millionProduction Barrels in 20 yrs Barrels in 7 yrs Barrels in 20 yrs
Reservoir studies have been completed. The pract.ical results will be known onimplementation of the recommendations of the studies.
Hamitabat Gas Field
The production potential of the gas .Ield has been enhanced, although gasdemand from this field has been reduce' by the recent implementation of a takeor pay contract for gas supplies from the Soviet Union.
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B. ECONOMIC IMPACT
Appraisal ActualEstimate (at Final Development)
EconomicRate of Retyrcn 61X 62.6%
UnderlyingAsIumDtions
1 US$26/Barrel of oil revenues, Production beginning in thirdUS$6/Barrel operating costs, year of construction. Oil12.5% royalty. production profile based on
output declining by 11% peryear from 1988 to 2000.
2 Net benefit to Turkey is Average oil price per BBLnet benefit to TPAO plus taken from Bank's priceroyalty revenues. prospects for Major Primary
Commodities (11/88), 1985=100
3 Average initial production Operating costs computed onof 100 barrels/day per new the basis of US$2/BBL ofwell and a 15% rate of decline production.per year.
4 Conversion factors used asfollows: Capital cost: .72Operating Cost: .79Taken from COD Working Papers"Economic And SocialAccounting Prices for ProjectAppraisals in Turkey" (4/86).Capital costs and operatingcosts deflated by MUV Index,1985=100.
Comments
As a result of the Bank's support in the Raman development program,TPAO was able to recommence oil production dnd produce 67,067 barrels in1982. Later, with the drilling of infill wells (19 wells) and working over of34 wells, TPAO was able to increase oil production to a peak of 277,377barrels in 1984. TPAO, in later years (1984-88), has been able to arrest thenatural production decline to about 5% per year by applying prudent productiontechniques.
The gross revenues from Raman production has increased from US$1.55million in 1982 to US$2.55 million in 1988. This increase is even moresignificant when it is considered that crude oil prices has declined by about50% (from US$26.5/bbl in 1982 to about US$13.7/bbl in 1988). TPAO has beenable to maintain its operating costs at about US$2/bbl during the period1982-1988. This has more than offset the impact of the decrease in the crudeoil price on the net revenues.
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C. FINANCIAL IMPACT
TPAO has met all the financial covenents. It is significantlystrengthened financially as an institution because of the project. TPAOachieved a debt equity ratio of less than 1.0, a currernt ratio greater than1.0, a debt service coverage ratio of 2.0 and an adequate working capital.TPAO always had plenty of local funds for project implementation. Despite asharp fall in oil prices, TPAO is able to carry on an adequate explorationprogram using dividends from its refining and marketing subsidiaries. For afurther discussion of TPAO's finances, see paras 4.11 - 4.19 of the PCR onLoan 1916-TU.
D. SIUDIES
Purpose as DefinedStudies at Apooaisal Status Impact of Study
Reservoir Study To determine the Completed successfully The study has evaluatedof the Raman optimum approach in June 1985, the reservoir potentialand Garzan Fields to a secondary about three years late. and made recommendations
recovery program for increasing thefor the entire recovery of oil. Thefield. practical results would
be known after implementa-tion of the recommended
pilot tests and the
development strategy.
Management Study To improve the Study completed in It addressed areas such
organization and June 1987, about five as organization, planning,
management of TPAO years later than cost control, personnel
originally planned. policies, budgetary
control, internal
reporting system and
administration. It also
made plans for installing
a management information
system. TPAO is taking
steps to instal this system.
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7. Status of Covenants
Section of AoreQment Substance of Covenant Extent of Cooliance
TPAO would:
PA Sect (a) Establish and maintain until project A project implementation unit for each
3.02 coepletion a project implementation part of the project was maintained
unit for each part of the project satisfactorily through the completion
adequately staffed with experienced of the project.
staff.
PA Sect (b) Transfer to IPRAS by January 1, 1981 Complied with, though late by a few
3.03(i) resporsibilities for importing and months.marketing of imported petroleum.
PA Sect (c) Transfer to IPRAS operational control Operational control was transferred
3.03(ii) of facilities for refining imported after the enactment, in May 1983, of
oil by July 1, 1981. the law restructuring TPAO.
PA Sect (d) Separate by 12-31-81 all the activi- Separation of activities was delayed.
3.03(iii) ties with respect to exploring Separation of activities was completed
producing, refining and distributing after the enactment in May 1983 of the
domestic oil from those with respect law restructuring TFAO.
to the importing of foreign petroleumand petroleum products.
PA Sect (e) Furnish to the Bank by December 31, TPAO's staffing problems continued
3.04 1981 recommendations to attract and through mid-1983. Arthur D. Little, a
retain qualified technical personnel consultant fin-, was hired to do a
and to improve the operational study, and by the end of 1984 the
efficiency of its staff, and there- implementation of recommendations was
after take appropriate steps to discussed. In addition, although late
implement such recommendations. TPAO revised the salary structure,
introduced incentives,provided training
facilities for the technical staff,
which has resulted in motivatingtechnical staff to remain with the
organization. Thus, though late, the
covenant has been complied with and, at
present, the morale of TPAO staff is
satisfactory.
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PA Sect (U) Not later than October 1, 1981 furnish Complied with.3.05(a) a phased implementation program for
the Bati Raman component and begineach subsequent phase only after theearlier phase has been satisfactorilycompleted.
PA Soct (g) Not begin thn field test in the Complied with.3.05(b) central section of Bati Raman
until the Bank agrees that the testresults in the western area justifybeginning such tests.
PA Sect (h) Establish. by October 1, 1981. a Panel not set Up, perhaps because3.06 Project Advisory Panel of Experts in project implementation was seriously
enhanced oil recovery, including at delayed.1^ast three foreign experts.
PA Sect (i) By April 1, 1981, establish as of Accounts were separated after the enact4.02 January 1, 1981, and thereafter ment, in May 1983, of the law restructu
maintain sepa-ate accounts and ring TPAO.financial statements with respectto internal and external activities.
PA Sect (j) provide the Bank a copy of its TPACO submitted its 1981 and 19824.03 audited accounts within six months accounts only by mid-1983. Audited
of the end of the fiscal year. accounts were also received for1983-1987.
PA Sect (k) Ensure that, by July 1981, TPAO shall By December 1981,the D/E ratio was less4.06(a) attain a ratio of its long-term debt I`- 1.0. It was brought down to 38/62
to its equity not greater than 1.0. by L y 1983. Thus the covenant wascompli-' with.
PA Sect (1) Ensure that, by July 1, 1981, TPAO's The cuiri t ratio was not less than4.06(b) ratio of its aggregate current assets 1.0 by Juli I- n 1983, it was
to its aggregate current liabilities marginally bel. 1.0. For 1984/87,is not less than 1.0. the current ratios were sati;factory.
PA Sect (m) On the first day of each month after Cash and lines of credit exceeded two4.06(c) July 1, 1981, have liquid working months of operating expenses in July
capital, marketable securities and 1981. Complied with also for theguaranteed lines of credit of at following years.least two months estimated operatingexpenses
PA Sect (n) Incur long-term debt only if proj- Crmpleted with4.07 ected net revenues are at least two
times the aggregate projected debtservice requirements.
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PA Sect (a) Beginning January 1, 1981, reTyrin Complied with4.09 from using internally generated
funds for its subsidiaries.
PA Sect (p) Until completion of the project, Investment program submited annually.4.10 furnish to the Bank annually
by October 'l of each year itsproposed invetment program for
the followiny year.
PA Sect (q) Beginning with fiscal year 1981. A unit was established by 04/81 to4.11 Annually revalue its assets complete revaluation of assets by
and submit to the Bank proforma 09/81. However, TPAO revalued itsaccounts and financial statements fixed assets during the first sixbased on such revaluation, months of 1983 in accordance with
the Fi-ed Assets Revaluation lawthat was enacted in the beginning of1983, which allows for only a one-time revaluation, not an annualreval uati on
GOT assured that:
LA Sect (a) If funds are inadequate to meet the There was no shortage of local3.31(b) local expenditures required for carr- funds necessitating GOT's help.
ying out the project, GOT would pro-vide such funds as -n equity contri-bution to TPAO.
LA Sect (b) If TPAO's accounts receivable There is no record of GOT ever3.02 exceed its sale for the previous being called upon to provida the
two months, GOT would provide such difference.difference.
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8. Use of Bank Resou cu
A. Staff InDut&
Stage of Planned Revised FinalProlect Cycle HQ Field HQ Field HO+Field Comments
Thru Appraisal 159.6
Post-Appraisalthru Bd Approval 11.3
Bd Approvalthru Effective. 2.0
Supervision 167.9/
Total 340_S
1/ In 1986 and 1987, when various implementation problems developed, thesupervision effort was rather meagre, having been only 12.3 and 14.6 manweeks respectively as against an average of about 24 man weeks per yearfor the entire impl.ementation period.
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B. Msih ns
PerformanceStage of No. of rays in Specialization Rating Types of
Project Cycle Month/Year Persons Field Reference 1/ Status a/ Problems I/
Thru Appraisal Nov. 1979 2 17 ECON, FNA -Jan-Feb '80 6 24 ECON, PET.EGR(2)
FNA(2), PRO, EGR -
Post-Appraisalthru Bd Approval June 1980 1 1 MAA
Nov. ,980 1 6 PET.EGR
Board Approvalthru Effectivenes Jan. 1981 3 12 ECON, FNA -
PET.EGR
Supervi.ionI Jan.1981 3 12 ECON 2 MTPII Nov.1981 3 14 PET.EGR, FNA 3 MTP
GEOLIII Apr.1982 4 14 MAA, FNA, Not Indicated
.ET.EGR, LCONIV Oct-Nov'82 1 14 PET.EGR 2 MPTV Aug.1983 1 5 ECON 2 MPVI Nov.1983 2 10 ECON,PET EGR 2 MPVII May 1984 3 7 PET.EGR, FNA 2 M
PRO.EGRVIII Oct.1984 4 7 MAA,FNA,GEOL 2 M
PET EGRIX Dec.1984 1 6 PET.EGR 2 TX Apr.1986 2 6 PET.EGR(2) 3 MTXI Dec.1987 3 8 GEOL,PET.EGR, T
DR.EGR
1/ MAA ManagementPET.EGR Petroleum EngineerGEOL GeologistDR.EGR Drilling EngineerECON EconomistPRO.EGR Procurement EngineerFNA Financial Analyst
2/ 1 Problem-free or minor problems2 Moderate prc"lems3 Major problems
3/ M ManagerialT TechnicalP Political
- 201 -
Bo-ti Rrmaon EOR ProjectPbnrw d and Mctud Dbumnwts
lo1
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20 - / ,,
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1961 1962 1963 1964 1965 1986 1967 1968 1969
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