Jake field, discovered in July, 2006, contains 10 oil-producing and 12 condensate gas-producing zones. The total number of drilled was 19, including 5 updip wells penetrated oil and gas zones, the remaining 14 downdip wells completed at principal oil zones. A unique co-development project of oil and gas had been performed since the start-up of field in July, 2010, including three phases:
Phase I: Prior to start-up of the field, In-situ gas injection was initiated. Single tubing string completion was utilized in updip wells, packer isolated oil and gas zones so that high-pressure gas could produce from the tubing and oil could produce from the annulus. After commencement, gas from updip wells was injected into downdip wells to maintain reservoir pressure and minimize water influx. The remaining gas was used to gas-lift at updip wells.
Phase II: Following pressure depletion of oil and condensate gas zones, gas-lift wells became inefficient. The packerless tubing string was extended to the bottom of perforations for commingling production of oil and gas condensate zones at updip wells. Well stream was produced from the casing annulus while recycling gas was injectied from compressors into the tubing for gas lift. Nitrogen injection was conducted at downdip wells.
Phase III: After water breakthrough, infill wells between updip and downdip wells were drilled for nitrogen injection to mitigate the water cut rising trend.
Actual production performance of oil and gas co-development is better than sequential production of oil and gas. Initial well production at two producers reached over 10,000 BOPD, Current recovery factor for oil is 25% and gas is 36%. Oil is producing at the level of 18,000 BOPD with average offtake rate of 5.8%. Simulation confirmed that ultimate recovery factor for oil could be over 50%.
khair, Elham Mohammed M. (Sudan University of Science & Technology) | Zhang, Shicheng (China University of Petroleum, Beijing) | Abdelrahman, Ibrahim Mustafa (Sudan University of Science & Technology)
The current study presents elastic properties model for Fulla Oilfield in northeast of Block 6 in south of Sudan. Due to the poor formation consolidation and relatively viscose fluid, reservoirs may predictably produce massive amounts of sand and numerous troubles were found in the field as a result of sanding. No documented researches were found to introduce good parameters for rock strength and rock failure conditions through the field. Therefore, an accurate technique for predicting rock failure conditions may yield good profits and improve the economic returns through preventing sand production from the formations. General correlations were presented to accurately describe rock strength parameters for the field; the work utilizes the application of the wireline porosities to be used as a strength indicator through the combination of rock mechanical theories with the characterization of Fulla oilfield. Log porosities (density, sonic and neutron) were calibrated with the core measured porosity, and the best matching porosity were correlated with the dynamic calibrated strength parameters by different correlations. The results support the evidence of the use of porosity as an index for mechanical properties; power functions were found more reliable than the exponential functions, and can be used with a high degree of confidence; also it is more accurate than the Shale Index model presented in previous work for same field; however, the result does not support the direct linear expression presented in the literature for other field due to the variations in the field conditions.
This paper illustrates the successful design, implementation and evaluation of cyclic steam stimulation pilot in heavy oil field of Sudan. This field contains heavy oil in multiple reservoirs of Bentiu formations of late cretaceous age occurring at epths of 550-600m. Reservoirs are highly porous (~30%), permeable (1000-2000 mD) and unconsolidated in nature. Fluid properties include viscous crude of degree API 15 - 17 and corresponding viscosities in the range of 3700 cp and 3000 cp at reservoir conditions.
In view of higher viscosities and consequently lower oil rates and envisaged meager primary recovery of around 18-20%, plan is made for thermal enhanced oil recovery (TEOR) application early to overcome the resistance to flow and maximize the recovery. As EOR processes are reservoir and reservoir fluid specific, therefore, it is prudent to understand the reservoir response to the steam injection before full field application. Cyclic steam stimulation has been implemented in eight selected wells spread over the field encompassing varying reservoir characteristics for understanding the efficacy of the process, acquiring the valuable data and operational experience. Equally important objective was to gain experience for minimizing the key risks, associated problems and challenges.
Wells have been completed with heat compatible casing and cement. Steam quality of 75% was injected for 6-12 days and wells were subjected to soaking of 3-5 days. Putting on production an improvement of three to five folds has been realized compared to primary production and first cycle is sustaining more than six months. Actual results are better than predicted in simulation studies with lower steam intensity of 120 m3/m compared to planned 160m3/m. Paper also discusses improvement in oil production and its variation with formation and fluid characteristics, formation thickness, depth of formations, duration of injection and soaking periods along-with response variables like oil-steam ratio and steam/water production. Operational challenges in preventing the heat losses in annulus, lifting challenges and sand production are also discussed.
This paper illustrates the natural gas in-situ huff and puff pilot test applied in Jake field in Sudan. B pool of Jake field is a medium GOR (100 scf/bbl) pool with medium well productivity, averaging at 500 BOPD by PCP testing. Operator intended to increase well output to reduce operational and safety hazards. Substantial high pressure natural gas below B pool could be utilized and injected into B pool to boost recovery factor. This process undergoes injection, soaking, production, similar to steam huff and puff. Pilot test of in-situ huff and puff has been planned by following methodology: 1) driving mechanisms investigation of huff and puff and confirm applicability in B pool; 2) gas production from tubing and injection into B pool through casing without using gas compressors; 3) injection and production parameters optimization by nodal analysis;
Pilot test on two wells JS-4 and JS-1 began in Aug. 2010 and flowed naturally after 20 days injection and gained 20 fold well rate increase compared with PCP wells, amounting to 10000-13000 BOPD, setting the highest well rate record in Sudan. Conclusions drawn from pilot tests were as follows:1) in-situ natural gas huff and puff was feasible; 2) gas injection could boost reservoir pressure and reduce in-situ viscosity and enhance recovery factor; 3) gas from tubing into casing was proved simple, efficient and cost-effective 4) production rates could be optimized using nodal analysis. Sudan is abundant in layered pools with lower gas and upper light oil, natural gas in-situ huff and puff has wide applications for similar pools in Sudan. Successful natural gas huff and puff pilot test in this paper highlighted huge oil rate gain, innovative well bore structure, cost-effective operation, paving the way for future full field implementation.
Liu, Bingshan (Research Institute of Petroleum Exploration and Development) | Zhou, Shi (CNPC Chuanqing Drilling Engineering Company Limited) | Zhang, Shunyuan (Research Institute of International Technologies of CNPC Drilling Research Institute)
The two main target formations of shallow horizontal wells in Sudan are Bentiu formation and Aradeiba formation. They are becoming more and more important with the exploration of oilfield, and they are all about or shallower than 1000m underground. The stratums are loose, so some measures are adopted to ensure the success of drilling operations: studying the stability of the borehole, optimizing the hole structure and casing program, establishing the drilling fluid system and its formulation.
We get the pore pressure, collapse pressure, and the fracture pressure by studying the formation pressure system using professional software upon the logging data. Study the relationship between the content of clay and the stability of borehole. It shows that the clay content has significant effect to borehole stability in Sudan. Then we analyze the collapse period of the upper stratums. The time window is about from 5 days to 7days. Based on the results and the study of the data of those wells drilled, the horizons of leakage and collapse are indicated. According this and the formation pressure, we optimize the hole structure and casing program. Finally, the KCl-polymer system is sifted as the drilling fluid. We determine the mud density according to the formation pressure first. Then the contents of KCl and the additives are indicated by experiments. According the experiments, the ideal percentage of KCl is form 6% to 8%, and the percentage of QS-2 in the drilling fluid using in field is from 3% to 4%. Now there are 5 shallow horizontal wells have been drilled in Sudan. The research achievements have been applied in the drilling operations. The average drilling cycle is about 17 days. Moreover, the hole diameter enlargement rate is decreased remarkably.
Bahuguna, Ajay (Oil & Natural Gas Corp. Ltd.) | Ahmed, Ramy (Schlumberger) | Ahmed, Mohamed Elbadri (Schlumberger) | Vazquez, Maria Leticia (Schlumberger Logelco, Inc) | Shaheen, Tarek | Sutrisno, Hermawan Joko
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.
Greater Unity a multilayered clastic reservoir in Sudan is a conglomeration of number of fault blocks- lacustrine deposits of late cretaceous age. Reservoir characteristics are mostly heterogeneous with varying degree of heterogeneities both vertically and horizontally. Reservoirs are highly undersaturated and have poor aquifer support. Rapid pressure decline was observed in early phase of production, severely affecting the performance of pumps resulting into frequent failures and causing sharp production decline. Water injection in low pressure mode was resorted in some blocks. Failure rates of ESP and PCP reduced significantly as dynamic fluid level (DFL) increased noticeably, provided sufficient submergence, and improvement in efficiency of the pumps.
Significant decline in injectivity in Aradeiba formation compelled to change the strategy of injection. Step rate tests were the guiding factor for selecting the low and high pressure injections and also stimulation. Paper discusses application of diagnostic methods like Hall plot, Jordan plot and other empirical relations using Pressure, injection and production data for understanding and improving the injection process. Profile modification for better conformance control gained early importance in view of smaller sizes of the pools.
Nonparametric statistical method known as Spearman rank analysis has been used to understand and analyze the degree of communication between injectors and producers. This analysis quickly identifies the communication between injectors and producers, or lack of communication and helps in understanding the response of injection. Preferential flow trends are reflected by the correlation in rates between injectors and producers along with lead time response of injection on production.
Paper illustrates the important ingredients which can add value to asset and improve the reserves and overall development strategy. Therefore, it is highlighted that success and failure of water injection project depends on why, when, where, what, how and how much to inject, plus what will happen to the formation once the water injection starts.
Fula is a heavy oil field located in Muglad basin in Sudan. Aradeiba reservoir in the field consists of highly heterogeneous sandstone that is thinly bedded, unconsolidated, bearing typical heavy oil. Bentiu reservoir is composed of massive sandstone, unconsolidated and traped very high viscous oil. Production performance of vertical wells indicates that the reservoirs are facing problems of low productivity, bottom water conning and sand production. In his circumstance CNPCIS set itself a daunting task of tripling the production in less than a year.
Horizontal wells were considered as best option for improving the productivity in this small to medium sized heavy oil field, and controlling the sand production due to low drawdown pressure and increased exposure the reservoir.
This paper discusses about comprehensive geological study , identification of target oil pools, well design, selection of fit for purpose technologies and the complete well placement cycle including detailed analysis on the drilling and steering challenges while placing horizontal well through reactive shales and channel sand environment.The paper also discusses about various completion strategies , the results of well placement, value of using new technology ,lessons learnt and cost /production analysis.
Team work, communication, knowledge sharing and deployment of fit for purpose technologies has resulted in a five fold increase in production through horizontal wells compared to vertical wells with no sand production. The paper illustrates how integration of different disciplines led to successful well placement, enhanced production with sand and water management in heavy oil environment.
Exploration and development of Heavy oil fields in Muglad Basin in Northern Africa started with conventional vertical wells and as time progressed this matured into drilling of horizontal and high angle wells.
Typically drilling challenges in this area include drilling of very reactive shale's, shallow kick off depths and high build rates. Unconsolidated sandstones and interbedded shale's are sensitive to mud weight and are prone to lost circulation.
First few horizontal wells were drilled with traditional technology of positive displacement motor with Silicate mud. Many of these wells faced hole cleaning challenges leading to pack off -excessive back reaming and stuck pipe incidences, uneven build rates via sliding in interbedded formation leading to high borehole tortuosity. It is significant to note that due to these difficulties one of the planned horizontal wells was sidetracked thrice after stuck pipe incidences and finally completed as a 30 deg deviated well with an AFE over run of 300%.
Taking leaf from experience of horizontal drilling in Muglad basin, rotary steerable system (RSS) has been deployed to drill horizontal well in Umm Bareira field. This field is shallow, highly unconsolidated and heavy oil with viscosity nearly 350 cp. This methodology of drilling has resulted into significant improvement in drilling performance, saving days and cost and eliminating stuck pipe incidences. Well has been completed openhole with sand control strategy using standalone screen with two swell packers for addressing the future reservoir management requirements like intervention for isolating the high water cut intervals in the horizontal section and better productivity and avoiding life cycle risks. Well produced 1300 bopd which is 5 times higher than vertical well and more so make production significant from the field. This paper highlights the learning curve of horizontal well drilling, completion and production of viscous oil field in Muglad basin.
Umm Bareira is a small heavy oil field in Muglad basin. Three exploratory and appraisal wells have been drilled in the field. Three hydrocarbon bearing layers have been encountered at the shallower depth. Viscosity of the crude oil in field is very high. Reservoir is highly permeable and unconsolidated. All the wells were tested through swabbing due to its viscous nature and productivity was very poor. Exploitation of the field by vertical wells only is not a feasible concept. Therefore, it has been decided to drill horizontal well and complete openhole which will provide maximum reservoir contact and also enable to delay the water production and control the sand incursion problem.
The development of oil-bearing basins in Sudan is closely associated with the global phenomenon of plate tectonics and particularly with the separation of Africa from South America trend. This west and central African Rift System extends from the Benue Trough in Nigeria to Cameron, Chad, Central African Republic and Sudan. The evidence for further southeast extension has been destroyed by Tertiary uplift associated with recent rifts in East Africa. The shear zone was identified by geophysical means, and has been demonstrated to experience right lateral movement in the Cretaceous. All the basins of the Sudanese rift-related system, such as the Muglad, White Nile, Blue Nile, Khartoum and the Atbara basins, terminate northwards at the Central African Shear Zone. The development of the rift basins of southern Sudan is related to the processes that operated not only within central Africa, but also along the western and eastern continental margins. The Sudanese interior basins are interpreted to be Mesozoic to Tertiary in age. Thus the Late Jurassic to Early Cretaceous Muglad Basin formed part of the West and Central African Rift-System.
The deep drilling coupled with geophysical data suggested the presence of sedimentary sequences of some 15000 m in the Muglad basin.
The subsurface continental sedimentation is structurally controlled and resulted in favourable juxtaposition of source, reservoir and seal. Abu Gabra and Bentiu formations deposited during rift Phase 1. Darfur Group and Amal formations deposited during rift Phase 2 and Nayil, Tendi, Adok and Zeraf deposited during rift-Phase 3. Most of the oil is accumulated in the Lower Cretaceous Abu Gabra and Bentiu formations and the Upper Cretaceous Darfur Group.
Copyright 2006, Society of Petroleum Engineers This paper was prepared for presentation at the 2006 SPE Asia Pacific Oil & Gas Conference and Exhibition held in Adelaide, Australia, 11-13 September 2006. This paper was selected for presentation by an SPE Program Committee following review of information contained in an abstract submitted by the author(s). Contents of the paper, as presented, have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material, as presented, does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Papers presented at SPE meetings are subject to publication review by Editorial Committees of the Society of Petroleum Engineers. Electronic reproduction, distribution, or storage of any part of this paper for commercial purposes without the written consent of the Society of Petroleum Engineers is prohibited. The abstract must contain conspicuous acknowledgment of where and by whom the paper was presented. Abstract Maximization of recovery from anisotropic small and medium size oil fields is a daunting task for operators. Development strategies and concepts implemented in large fields generally are not appropriate for small and medium size fields. Inappropriate strategies and methodologies of exploitation affect the overall recoveries and economics of the project. This is further complicated in tight, viscous and sand incursion prone formations. This paper discusses about number of small fields located in Muglad basin wherein oil accumulation is found in multiple layers of late cretaceous deposits. The formations are heterogeneous, unconsolidated with higher viscosity and strong aquifer support. Some formations are tighter too. Field performance is marred by exponential rise of water cut due to adverse mobility and lifting through ESP. Production is affected due to poor influx in tighter formations through conventional wells. This behavior is limiting the producing life of existing wells, resulting into decline in production and causing significant bypassed and undrained oil. Horizontal wells with state-of-art completion both in openhole and cased holed with suitable artificial lift techniques were considered as one of the IOR option for maximizing well productivity in these thinly bedded heavy oil field with objective for tapping the bypassed oil and delaying the water production while controlling the sand production. Lessons learnt and results of the well placement along with cost/production analysis will be presented. Production results to date have been remarkable with productivity improvement factor varying 3-4 folds compared to vertical wells.