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Mohammed E.S.,GNPOC | Ali H.A.,Sudanese Petroleum Corporation
Society of Petroleum Engineers - SPE International Heavy Oil Conference and Exhibition 2014: Heavy Oil Innovations Beyond Limitations | Year: 2014

Greater Bamboo field is located in block 2A Muglad Basin consist of four structures, bamboo west, main, east and south and covers an area of about 144km. It involves of, multi-layered under-saturated sandstone reservoir of late cretaceous ages buried at depth ranging from 1000m to 1500m with crude oil viscosity ranges from 200cp to 3000cp. The total Field STOIIP and RF is currently estimated at around 509 MMSTB, 16% respectively, to date the field had recovered more than 69% of the EUR.The field initially produced around 20,000STB/D with early water breakthrough and very minimal gas production rate until today. However, the production rate decline rapidly when the water production rate increased. Major factors that contributed to this problem are possibly due to the fingering and water conning. Currently the field is producing around 9000STB/D with water cut around 75% and keeps increasing. Since the declining production take place for that our strategy to go for implementation of Enhance Oil Recovery (EOR) process. After more study we conclude to use thermal EOR in Bamboo field reservoirs, Feasibility studies shows that steam injection is potentially the most practical and viable option. In this paper feasibility study from screening, design optimization as well as implementation of cyclic steam stimulation (CSS) in BBW 42 as first well of this project will be presented in addition to various challenges and recommendations. The Result shows that the thermal EOR projects for bamboo west oil field are very successful and almost reward double production from 280 bbl/day to 500 bbl/day in Bamboo Oil Field. Copyright © (2014) by the Society of Petroleum Engineers All rights reserved. Source


Ibrahim M.M.,GNPOC
Society of Petroleum Engineers - North Africa Technical Conference and Exhibition 2012, NATC 2012: Managing Hydrocarbon Resources in a Changing Environment | Year: 2012

Is shale gas feasible in lacustrine basins? Shale gas has become an increasingly more important source of natural gas in the United States over the past decades. Less attention given to shale gas in lacustrine basins and the few cases are not encouraging. Abu Gabra formation act as the main effective source rock and reservoir in the same time gross thickness reach to about 7000m at the depocenter and characterized by the interbedded sands which producing condensate, light oil and recently considerable volumes of associated and dry gas. Geochemical evaluation carried to evaluate the source rock, pyrolysis analysis results of 617 geochemical rock samples from Azraq wells and 337 geochemical rock samples from Neem wells, used to evaluate the richness of source rock (TOC), kerogen type (HI, S2) and thermal maturity (Tmax). VRo readings of 119 rock samples from Azraq wells and 73 geochemical rock samples from Neem wells used to measure the thermal maturity. 1D modeling done to predict the geothermal history and heat flow of the study area. The geomechanical characteristics of the source rock (brittleness) evaluated using the mineral and metal analysis result of 3 core samples from selected wells. Based on the main key parameters used to evaluate shale gas in Marine basins there is high feasibility of shale gas in Lacustrine basin, where the average TOC in the study area (2.0 wt% - 3.0 wt%), VRo (0.48 C″″ 1.0 to penetrated intervals) high heat flow (peak in tertiary 83 mw/m2). High challenge of; litho-facies variation within short distance (difficulty of detecting sweet spot), suppression of thermal maturity, technological challenge of fracturing tools stands there to answer whether it will be success and economical viable?.. Copyright 2012, Society of Petroleum Engineers. Source


Kumar A.,Schlumberger | Omer M.,GNPOC | Sulaiman A.B.A.,GNPOC
Society of Petroleum Engineers - North Africa Technical Conference and Exhibition 2012, NATC 2012: Managing Hydrocarbon Resources in a Changing Environment | Year: 2012

Greater Nile Petroleum Operating Company (GNPOC) is facing challenges to sustain their production, which has been declining at the rate of 15% (approximate) annually. Major part of production is sustained by drilling infill wells recompletion. Pipeline network plays important role in delivering the production from wellhead to Field Processing Facility (FPF). Bottlenecks in pipeline can cause rise in wellhead pressure, which can have impact on production substantially. To identify these bottlenecks and reduce backpressure effect on network GNPOC initiated a project for de-bottlenecking of production pipeline network nine fields. A high fidelity Surface Network Model was developed for all field of GNPOC, which have more than 400 producing wells. This surface network model will help to quickly identify and accurately quantify bottleneck and other opportunity to reduce backpressure on the system and improve production. This model will also help in further field development, pipeline tie-in / lineup, best nearby Oil Gathering Manifold (OGM) to tie-in new wells etc. The approach of building model is kept simple, robust and scalable. Scalable model will helps GNPOC to add-in well model and integrated this production model to reservoir simulator, facility model and real time data easily and quickly. The model would also assist in evaluating field operation and development plan and expedite the engineering decision process. The identified bottleneck has been ranked in order or priority (which needed immediate attention). A totally new approach was adopted in the study in terms of the location, training and technology transfer in Sudan. The project engineer worked in close association with operation engineers from field and office. Also actual work has been partially carried out in field as well as office. This approach has given more opportunity to field operation engineers to interact with current modeling tool and technology and increase confidence level. This paper describes the development of the surface network model for nine fields of GNPOC, technical & project management challenges faced and the way ahead. The model includes the production and transportation networks. This paper also includes major de-bottleneck areas in the production network of GPNOC and How to make effective use of this model for engineering analysis. Copyright 2012, Society of Petroleum Engineers. Source


Shaheen T.,Schlumberger | Ghazi H.B.,Schlumberger | Abdalla F.A.,GNPOC | Izat A.M.,GNPOC
SPE Production and Operations Symposium, Proceedings | Year: 2010

After producing for more than nine (9) years, many wells in Sudan are suffering from lower production rate and increase in the skin value due to formation (Sand Stone) damage. Only re-perforation technique was used to mitigate formation damage problems; however, the results were not satisfactory. Considered the first time in the history of oil production in Sudan, Some of the idle producer wells in Greater Nile Petroleum Operating Company (GNPOC) operations fields were selected to treat their formation damage problems and to start the first Matrix Stimulation Engineering treatment. The results were outstanding where the oil production rate went up in the well TS-21 from 23 bopd to 1360 bopd. The well is still sustaining the high production rate after one year of treatment. The great success encouraged the implementation of the Matrix Stimulation treatment in different fields like Simber West where the results of the well SW-1 reached from 10 bopd to 900 bopd. This paper discusses the methods used in identifying the Matrix Stimulation candidates and the innovative solution including the lab tests and the chemical work done in order to determine the best fit for purpose chemical treatment to bring the wells back to production and optimize the production trend in the field of Toma South and Simber West. It describes the Matrix Stimulation of the well TomaSouth-21 as an example. Furthermore, it describes the entire lesson learnt from the execution and operation phase Last but not least, it shares the outstanding results and the way forward for the Matrix Stimulation business in Sudan. It gives a good reference and database for the stimulation treatment in Sudan since this paper is the first one to be written regarding Matrix Stimulation treatment in Sudan. © 2010. Society of Petroleum Engineers. Source


Bahuguna A.,GNPOC | Elbadri Mohd.,GNPOC | Alvarez M.L.V.,Schlumberger | Shaheen T.,Schlumberger | Ahmed R.,Schlumberger
North Africa Technical Conference and Exhibition 2010, NATC 2010 - Energy Management in a Challenging Economy | Year: 2010

Munga field of the Greater Nile Petroleum Operating Company (GNPOC) in Sudan has several wells that have commingle production from the Aradeiba, Bentiu-1 and Bentiu-2 formations. These formations are highly variable in terms of the reservoir properties, oil types and pressure regimes. Because of the contrast properties of different layers, the water cut phenomenon is relatively fast and severe which hampers the productivity and ultimate recovery of the individual well as well as the field. For effective Reservoir Management and to limit the declining trend of the field, Water Management Techniques are applied in some of the wells of this field. Information obtained in the process was used for reservoir model calibration, well productivity prediction, low productivity diagnosis, and generation of new drainage points and remedial action for water management. This paper discusses the technical details of three cases corresponding to the wells Munga-XX and Umm Sagura South-XX (USS-XX) and Munga-XY in which, a multidisciplinary approach has been implemented in order to determine depletion profile, produced oil and remaining reserves, locate any "by-passed" oil zones, determine oil and water contributions from each zone and shut off the excess water production while maintaining or increasing oil production. The source of water entry was identified in multi-rate production logging using Production Services Platform and electrical probes through Y tool-ESP completion. Vx meter was carried out at surface to real time monitoring the well production during the production logging survey. The well depletion profile was determined using Cased Hole Formation Resistivity (CHFR*) tool. A multidisciplinary team processed and interpreted the logging data and based on the results remedial jobs were carried out The general outcome of the remedial jobs based on this approach was a considerable reduction in water production in both Munga-XX and USS-XX wells as well as oil production gain, making this a successful job. Copyright 2010, Society of Petroleum Engineers. Source

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