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Elhag, Hani Hago (Asia Pacific University, Malaysia) | Abbas, Azza Hashim (Asia Pacific University, Malaysia) | Gbadamosi, Afeez (Afe Babalola University, Nigeria) | Agi, Augustine (Universiti Teknologi Malaysia, Malaysia) | Oseh, Jeffrey (Afe Babalola University, Nigeria) | Gbonhinbor, Jeffrey (Niger Delta University, Nigeria)
Abstract Recently, continuous surfactant flooding (CSF) has been devised as an improvement to overcome the limitation of conventional surfactant flooding (SF). The utilization of CSF depends on several factors such as surfactant type and reservoir characteristics. This study performs the feasibility study of utilizing CSF for a marginal field of Bentiu reservoir in Sudan with a production history of 20 years. The reservoir is moderately heterogeneous reservoir. Thirty-six (36) cores from the natural reservoir extension of its most effective basin were evaluated. The evaluation focused on the role of core properties such as porosity and permeability on CSF. The comparison of the results was benchmarked by water flooding and the conventional surfactant flooding. Numerical simulation CMG STARS was used to perform the sensitivity analysis on the core scale. The results of the study showed 5 main ranges of the cores available after grouping. The highest recovery factor of water flooding was in the range of 48 (+/- 1.3%). There were no significant changes in the cumulative oil produced; however, the core physical properties affected the duration needed to reach the production plateau. For CSF, the highest recovery was in the fourth group of cores. In term of water cut, the percentages declined slightly with a range of 0.01 to 0.09 % with lowest percentage value water cut recorded at 99.90% and the highest result of 99.99%. Moreover, the recovery factor reached up to 45.80% using water flooding method and increased up to 90.41 % in CSF method. The remaining oil saturation reached to 0.35 during water flooding and dropped to 0.061 during the CSF. Moreover, the result obtained in CSF which indicates that the optimum porosity and permeability range of 0.26 to 0.29 in porosity and 390 to 2220 mD in permeability is the suitable range to be implemented in continuous surfactant application. Hence, based on the obtained results, CSF shows promising effects for use in marginal oil fields.
Tang, Xueqing (1Petro Energy Co., Khartoum, Sudan) | Dou, Lirong (1Petro Energy Co., Khartoum, Sudan) | Wang, Ruifeng (2RIPED, PetroChina, Beijing, China) | Gabir, Alsadig Mohmoud (1Petro Energy Co., Khartoum, Sudan) | Musa, Mouiz Hamza (1Petro Energy Co., Khartoum, Sudan)
ABSTRACT Fula field at Block 6, Sudan contains crude of 16.8 to 19 °API with in-situ viscosity of 497 cp in Bentiu formation. It was on production in March, 2004 and has produced 14% of original oil in place. Massive and unconsolidated sandstones inter-bedded with thin (3 to 13 ft) and discontinuous shales possess high horizontal and vertical permeabilities (2 to 9.53 Darcies). Lateral dimensions of shale bodies range from 1,000 to 2,000 ft. To extend oil production life with water-free, initial development strategy was to perforate the upper and more permeable zones (Perforations are 30% of entire zones) to obtain profitable productivity. After fieldwide water breakthrough, based on the studies of bypassed oil distribution, the following innovative deeper re-completions have been applied in high-water-cut wells (water cut more than 80%) to exploit the bypassed oil zones and new pay zones that have been missed below the existing productive zones. squeeze cement into the existing high-water-cut zones, located at the upper portion of entire pay zones. Those long wormholes communicating with aquifer caused by deep sanding should be cemented. perforate partially the lower portion of pay zones with optimal shot density. 30 to 40% of entire pay zones and shot density of 5 shots per foot are recommended. Perforation tunnel optimization can be run for concrete well conditions. Progressing Cavity Pumps operate at low frequencies less than 30 Hz to regulate proper pressure drawdown less than observed critical value of sanding from field tests and water coning. Field production data indicate that this workover campaign has achieved more than 2-fold oil gain and reducing water cut by 30 to 50% compared to previous water cuts of over 80%, also, water cut plus dynamic fluid level remain relatively stable over 6 months.
Weili, Ke (1Research Institution of Petroleum Exploration and Development, PetroChina, Beijing, China) | Guangya, Zhang (1Research Institution of Petroleum Exploration and Development, PetroChina, Beijing, China) | Aixiang, Liu (1Research Institution of Petroleum Exploration and Development, PetroChina, Beijing, China) | Yonglin, Zheng (2Petro-Energy Co., Ltd., Khartoum, Sudan) | Yongjun, Yu (2Petro-Energy Co., Ltd., Khartoum, Sudan)
ABSTRACT Fula sub-basin is one of chasmic structure units with rich petroleum accumulation within Muglad basin. In the past, thick sandstones of Bentiu was considered as main petroleum accumulation targets sealed by faults and anticlines, and most petroleum generated by AG source kitchen has migrated to upper formations along big faults, and furthermore, sandstones inside AG formation of are thin with poor permeability and porosity caused by compaction. Recently, some works have been done specially on AG formation, including small fault interpretation, seismic sedimentary analysis and thin layer inversion, resulting in new petroleum discoveries within middle AG formation, which reveals that AG formation has also good petroleum accumulation abilities. Comprehensive study shows that there developed many small faults within AG period, which could seal sandstones of AG formation laterally, forming effective faulted block within AG formation. Sandstones of delta and sub-water channel could be found. Within AG4 and AG2 formations, there are mainly lacustrine facies. Channel sandstones occurred regression and the area of alluvium fan decreased AG shale has high matter abundance, high hydrocarbon generating potential and kerogen type I, II with middle to high mature, showing good hydrocarbon generation ability. Although sandstones of AG formation have relatively low permeability and porosity, these sandstone have good logging response on hydrocarbon could be sealed by local surrounding mudstones and. All above reveals that AG combination is near-source reservoir combination. Low-amplitude anticline and structure-lithology reservoir models are favorite reservoir models in Fula sub-basin. In the west slope, especially the lower places of the slope are the areas of huge sedimentary accumulation should be favorite prospects. As for the east slope, low-amplitude anticline bounded by small faults that developed during AG period should be the favorite area for exploration, which has been proved by successful drilling activities. In Fula sub-basin, AG structure-lithology complex reservoir combination should be the favorite type for drilling as per under these two key factors, the petroleum could be well accumulated. Currently, there have two important petroleum discoveries of channel sandstone and delta sheet sandstone in AG formation, proving that AG formation still has good potential for drilling.
Abstract This paper illustrates an innovative field-scale application of injecting condensate gas and recycling gas in Jake field, Sudan. This field has two production series, namely AG condensate gas pools and Bentiu oil pool from bottom to up, with the former 3520 ft. below the Bentiu reservoir and 1695 psi of initial reservoir pressure difference. Bentiu pool of Jake field is a medium crude oil (29 API) pool with strong aquifer support. Well productivity was 500 BOPD. Operator intended to inject high-pressure condensate gas into Bentiu pool to increase field output, whereas was confronted with following challenges: 1) injection of condensate gas in an easy-to-operate wellbore configuration; 2) optimization of injection parameters to achieve highest output; 3) suppress aquifer water breakthrough. Field scale application had been optimized and implemented since 2010:1) High-pressure condensate gas had been injected into two updip crest Bentiu wells in the same well bore, following a huff-and-puff process, well output amounted 4,000 to 13,800 BOPD under natural flow; 2) 1/4 recycling gas volume from compressors was re-injected into 12 downdip wells at controllable pressure to avoid early water breakthrough; 3) The remaining recycling gas was utilized to gas-lift other five updip wells. Oil producers were reduced from 19 to 7 comparing to original field development plan, while oil rate ascended from 22,000 to 30,000 BOPD, with watercut dropping to 7% from 15%, achieving a high offtake rate of 6%. Reservoir simulation indicated ultimate recovery factor is expected to be over 50% with such full-field gas injection. Conclusions drawn from field scale injection of condensate gas and recycling gas were as follows:1) condensate gas injection in the same well bore was technically innovative and operationally robust; 2) recycled gas injection into downdip wells helped detain water breakthrough; 3) field scale application had evidenced outstanding success with high output and high offtake rate.
Abstract 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 m/m compared to planned 160m/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 international technologies of CNPC drilling research institute) | Zhou, Shi (CNPC Chuanqing Drilling Engineering Company Limited) | Zhang, Shunyuan (Research institute of international technologies of CNPC drilling research institute)
Abstract 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.
Abstract 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.
Abstract Conventional pressure transient testing, using a pressure gauge positioned at a fixed depth in a well, has historically been the main source of permeability and skin estimation in formations. However, if a well is completed as a multi-layer commingled producer, then this conventional approach makes it difficult to measure the permeability and skin of individual layers. Greater Munga field of the Greater Nile Petroleum Operating Company (GNPOC) in Sudan has several wells that commingle production from the Aradabia, Bentiu-2 and Bentiu-3 formations. These formations are highly variable in terms of the reservoir properties, oil types and pressure regimes. A selective inflow performance (SIP) test was carried out during production logging (PL) jobs in some of these wells and it indicated that the productivity index (P.I.) of the individual layers varies widely, ranging from 1.5 to 15 b/d/psi. This illustrated the need for a method to estimate the permeability and skin of each layer. This information was needed for reservoir model calibration, well productivity prediction, low productivity diagnosis and remedial action selection. Two solutions were proposed to GNPOC; use the conventional technique of isolating each layer and testing it separately or carry out a commingled multi-layer transient (MLT) test with a PL tool. In an MLT test, in addition to the normal PL runs, individual pressure transient stations are also recorded at the top of each contributing layer. The MLT test measures the flow rate and wellbore pressure above each producing layer for different surface flow rates during the infinite-acting phase. These individual layer flow rates and pressure transients are used to calculate the individual layer properties. GNPOC decided to go in for the MLT testing option and two wells were analyzed. In the first well, MLT testing showed that one of the layers had a very high permeability compared to the other layers. It depleted much faster and had early water breakthrough. Consequently a water shut-off job is planned for this layer. In the second well, MLT analysis showed that the upper layer had poorer permeability as compared to the lower layers. However, this layer holds good oil reserves. Hence, this well is a good candidate for future side tracking into the upper layer, in order to exploit the untapped reserves in this layer. In this paper, we will discuss the MLT testing technique, introduce a workflow for the analysis, and then will discuss the results of the analyses for two examples from GNPOC. Based on the success of these cases, multi-layer transient testing is estabilished as a preferred testing technique in this complex reservoir environment.
Abstract 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. Introduction Numbers of oil-bearing fields have been discovered in Muglad basin in the concession area operated by GNPOC. Areal extent of these fields varies from 0.5 Sq Km to 35–40 Sq Km. Some of the major fields are namely Unity, Toma South, Neem and Heglig. In place oil volume varies from 5 MMSTB to 500 MMSTB. Depth of oil-bearing formation varies from 1200m to 3100m. The Unity area is located in the upper Nile province of the Republic of Sudan, approximately 1,400km away from the coast of the Red Sea and 730km southwest to Khartoum. Greater Unity which comprises more than 20 fault- blocks is the biggest field in terms of oil inplace and number of wells (Fig-1). Greater Unity field was discovered in 1980 and was put on production in June 1999 and comprises of number of fault blocks. Main-Unity is the largest block representing ca. 40% of the total in-place. Other fault blocks are small to moderate in sizes. A number of satellite fields have been discovered nearby to these major fields. There are some isolated fields away from the existing fields. It covers a relatively wide area some 20 km comprising more than 20 discovered structures. The multi-layered oil-bearing formations were penetrated from as shallow as Ghazal at ∼1800 mkb to as deep as Bentiu at ∼ 2800 mkb. Four main reservoir groups have been encountered in these fields namely Ghazal, Zarqa, Aradeiba and Bentiu with several sub-units within the major reservoir group with varying fluid contacts. It is highly faulted with shifting fault planes with depth in some structures. The reservoir properties are generally moderate with moderate to light oil properties of 28–35 API and relatively low oil viscosities of 2–15 cp. 2P STOIIP is around 1175 MMstb with EUR of 375 MMstb representing a RF of ∼ 32%. Greater Unity fields are developed by 100 producers supported by 23 injectors. All producers are supported by either Progressing Cavity Pump (PCP) or Electrical Submercible Pump (ESP). Fig-2 shows the historical performance of Greater Unity field.
Abstract 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. Introduction 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. Geological Setting 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.