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.
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.
Exploration and development of Heavy oil fields with high water cut and sand production in Muglad basin in Northern Africa started with vertical wells and as time progressed matured into drilling Horizontal wells.
Typically drilling challenges in this area include drilling very reactive shales , shallow kick off depths and high build rates, unconsolidated sand stones interbedded with shales which are sensitive to mud weight and are prone to lost circulation.
First few horizontal wells were drilled with conventional technology of positive displacement motor with silicate mud. Many of these wells faced hole cleaning issues 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 side tracked three times after stuck pipe incidences and finally completed as a 30 degree deviated well with a total cost over run of 300% above AFE.
Since then Rotary steerable system has been deployed to drill these challenging wells with significant improvement in drilling performance ,saving days and cost and eliminating stuck pipe incidences. This paper compares the performances of drilling with PDM Vs RSS in the same reservoir and presents the lessons learnt. A cost benefit analysis has also been performed and it clearly shows that RSS is both technically and economically a sound approach to drilling horizontal wells in Muglad basin.
Horizontal well drilling campaign in Sudan was started in 2004 with the following objectives:
• Increase well bore exposure to reservoir and hence increase the rate of production of heavy oil.
• Decrease the near well turbulence and hence decrease sand production.
• Decrease of Draw down pressure which will eventually lead to decrease in water cut.
The candidate wells were chosen in very well developed fields targeting by passed oil. Presence of good number of close by vertical offset wells offered good geological control for well placement. On the drilling front there were lots of challenges that were encountered while drilling the horizontal wells. In this paper we will look into the evolution of drilling techniques from the first well to the recent wells and see how continuous adoption of new and fit for purpose technology has minimized drilling risks and lead to economical drilling of horizontal wells.
Drilling Challenges in Muglad basin
Drilling of horizontal wells require in depth knowledge about the formations in the basin. Clear understanding of problems posed by the formations will go a long way in mitigating the drilling risks.
Figure 1 shows the formation stratigraphy of muglad basin Tendi and Nayil Formations are predominantly made up of water sensitive shale formations, which at times lead to bit and stabilizer balling. The next formation below is the Amal massive sandstone. Amal sand can be abrasive in some areas and usually have issues of lost circulation; build up of well bore deviation. Below Amal sand stone is Ghazal and Zarqa formations. These are made of consolidated sand shale intercalations and do not pose any major drilling problems. Aradeiba formation that lies beneath Zarqa can be sub divided into two major bodies, the upper and the lower Aradeiba shales. Both these formations are strong water sensitive and result in borehole instability, tight spots, pack off even while drilling vertical wells. The lower Aradeiba also has some sand stone reservoirs embedded between the shale bodies which contain some promising reserves. Bentiu reservoir is primarily a sandstone reservoir, which has very low pore pressure gradient. Differential sticking is one of the major concerns in this formation.
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.
Tewari, R.D. (GNPOC) | Raub, M.R.B.A. (GNPOC) | Omar, M.I. (QP) | Fenghan, B. (GNPOC) | Moris, M. (GNPOC) | Jelani, J. (PRSS) | Ramachandran, S. (AWT) | Fooks, A.L. (AWT) | Peden, J.M. (AWT) | Montague, Eamonn T. (Brunei Shell Petr. Sdn. Bhd.)
This paper describes the importance of well construction & well integrity and its relationship to reservoir management. Productivity enhancement studies in combination with reservoir simulation modeling on the Greater Heglig fields have revealed that well performances and production related problems were largely related to poorly designed wells and poor cementing practices. As a result, water channeling and cross flow across wellbore dominated true well performance characteristics contributing to very high water cuts in the majority of the producers in Greater Heglig fields. Separating the mechanically induced well behaviour from reservoir behaviour helped history matching the wells greatly, findings of which were subsequently validated during the study through running of ultra sonic imaging tool. The ultra sonic logging campaign proved the existence of channels, micro annuli's and cross flow across the wellbore causing a "water channeling phenomena" of up to 90% water cut across majority of the wells. As part of the productivity enhancement program for the Greater Heglig fields, a total of 23 sidetrack candidates have now been identified to capture the remaining developed reserves of ca. 30.0 MMstb, which will otherwise remain unproducible from the existing wellbore's. In addition to this, fit for purpose sidetrack well designs and construction together with good cementing practices will be required to ensure well integrity to improve reservoir management of the Greater Heglig fields.