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.
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.
(1). 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.
(2). 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.
(3). 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.
Fula field is located at the east part of Fula sub-basin, South Kordofan State, southeast of Sudan. It was discovered in May, 2001by the exploration well Fula North-1, which intersected both 34 ft of oil-bearing Aradeiba reservoir and 174 ft of oil-bearing Bentiu reservoir, with oil-bearing area of approximate 1,977 acres. Bentiu formation, of Cretaceous age, is the main producing horizon of the field. Structurally, as shown in Fig.1, is characterized by an elongated horst block controlled by two main normal faults. It includes a sequence of relatively massive sandstones interbedded with thin shales in 3 to 13 ft, deposited in braided river environment, with active bottom aquifer support (Fig. 2).
Tang, Xueqing (RIPED, PetroChina) | Dou, Lirong (RIPED, PetroChina) | Wang, Ruifeng (Petro Energy Co.) | Wang, Jie (RIPED, PetroChina) | Wang, Shengbao (RIPED, PetroChina) | Wang, Jianshun (RIPED, PetroChina) | Shi, Junhui (RIPED, PetroChina)
Jake field, discovered in July, 2006, contains 10 oil-producing and 12 condensate gas-producing zones. The wells have high flow capacities, producing from long-perforation interval of 3,911 ft (from 4,531 to 8,442 ft). Production mechanisms include gas injection in downdip wells and traditional gas lift in updip, zonal production wells since the start-up of field in July, 2010. Following pressure depletion of oil and condensate-gas zones and water breakthrough, traditional gas-lift wells became inefficient and dead. Based on nodal analysis of entire pay zones, successful innovations in gas lift have been made since March, 2013. This paper highlights them in the following aspects:
As a consequence, innovative gas-lift brought dead wells back on production, yielding average sustained liquid rate of 7,500 bbl/d per well. Also, the production decline curves flattened out than before.
Discovered in July, 2006, Jake field is situated at the north part of Fula Western trend with oil-bearing area of approximate 45,714 acres. This field contains two distinct productive formations in the Early Cretaceous age: Bentiu oil reservoir at the average depth of 4,724 ft plus Abu Gabra gas-condensate reservoir at the average depth of 8,425 ft. The producing reservoirs are normally pressured, and the field has a normal geothermal gradient of approximately 2.60℉/100 ft.
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.
Although heavy oil producers in Block 6, Sudan have been difficult to exploit with gas lift because crude oil has 19 °API, the reservoir pressure was low, and surface dead oil viscosity ranged from 30,000 to 40,000 cp. New advances have recently been made to increase oil production. These innovative practices include:
(1). Injected condensate gas into the reservoir prior to gas lift, and soaked for a time (e.g.one day) sufficient for condensate-gas to dilute the heavy oil's API gravity, reduce viscosity, and pressurized the zone near the wellbore.
(2). Large tubing string was extended to near the bottom of perforations, gas lift valves were not utilized to ensure that a continuous volume of high-pressure condensate gas was injected into the annulus, could blend with heavy oil at the bottom hole and avoided multi-point injection caused by possible sanding.
(3). Sand trap was installed to capture the produced sand.
(4). Injection pressure and injection gas rate were optimized to produce more condensate from the gas condensate reservoir for dilution of heavy oil at the wellbore.
Field data show that these new techniques have gained excellent results, with oil gain of 6-fold compared to average oil rate by PCP.
FN field is located in the northwest region of the Muglad basin in southwestern Sudan, with area of approximate 2,471 acres. The majority of heavy oil in FN field is contained in Bentiu formation occurring at the depth of average 4,100 ft. Structurally, Bentiu pool is characterized as an elongated horst block controlled by two main normal faults (Fig.1). it has low original pressure gradient, 0.38 psi/ft, Its initial reservoir pressure ranged 1500 to 1600 psia and reservoir temperature was 147?.
Bentiu pool is characterized by a thick massive reservoir, thick bed of unconsolidated sands interbedded with thinner beds of clays in 3 to 6 ft. or less, with porosity ranging from 24.2 to 34%, oil saturation in the range of 61 to 86%, and permeability in excess of 3000 md, net oil pay thickness amounts to 90 to 130 ft. Comprenhensive geological and reservoir engineering studies indicate that Bentiu reservoir is believed to be almost homogeneous, with active bottom aquifer.
Crude oil has API gravity of 19, and dead oil viscosities vary from 6,000 to 40,000 cp at 84 ?(the annual mean ambient temperature at the field).
Commercial production in FN field began in March, 2004. Cold heavy oil production with sand (CHOPS) technology was applied in the field, and Progressing Cavity Pumps (PCPs) were installed in heavy oil wells to lift the oil due to their ability to handle sand. The pumps were all equipped with Variable Speed Drive (VSD), VSD was designed to control pump speed and production, providing PCP with smooth work for start-up, frequency adjustment for sand control and avoiding early water breakthrough caused by aggressive pressure drawdown. For those PCP wells with crude viscosities between 6,000 and 10,000 cp, The average rate of single well was 470 BOPD, In Oct. 2009, it declined to 250 BOPD per well.
However, PCP encountered some operational challenges in viscous crude wells, e.g. gas-free crude viscosities from 30,000 to 40,000 cp. PCP only worked at low frequency less than 30 Hz due to high-torque caused by viscous heavy oil compared to allowable full frequency of 60 Hz, rod parting, and high flow line pressure drop.
Rao, Liangyu (Research Inst. of Petroleum Exploration and Development, PetroChina) | Wu, Xianghong (Research Inst. of Petroleum Exploration and Development, PetroChina) | Wang, Hui (Research Inst. of Petroleum Exploration and Development, PetroChina)
Copyright 2013, International Petroleum Technology Conference This paper was prepared for presentation at the International Petroleum Technology Conference held in Beijing, China, 26-28 March 2013. This paper was selected for presentation by an IPTC Programme 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 International Petroleum Technology Conference and are subject to correction by the author(s). The material, as presented, does not necessarily reflect any position of the International Petroleum Technology Conference, its officers, or members. Papers presented at IPTC are subject to publication review by Sponsor Society Committees of IPTC.
Pan, Xiao-Hua (Research Inst. of Petroleum Exploration and Development, PetroChina) | Yuan, Sheng-Qiang (Research Inst. of Petroleum Exploration and Development, PetroChina) | Ji, Zhi-Feng (Research Inst. of Petroleum Exploration and Development, PetroChina) | Hu, Guang-Cheng (Research Inst. of Petroleum Exploration and Development, PetroChina) | Liu, Li (China Petroleum Engineering & Construction Corp, PetroChina)
With the exploration activities of China National Petroleum Corporation (CNPC) in Sudan, Chad and Niger, more and more 2D, 3D seismic data had been required, a series of exploration and appraisal wells had been drilled, and more of other geologic materials had been obtained, such as well logs, core, geothermal gradient data, geochemistry data etc. Based on these abundant data and integrated application of geophysics method, physical modeling, computer modeling and geological analysis etc., the authors carried out an in-depth study on the Western-Central African Rift Basins (WCARBs), coming up with an understanding that the Basins are of passive rifts different from the so-called active ones formed in result of mantle up-welling. The WCARBs present unique petroleum characteristics including low geothermal gradient, aggregate thin-bedded hydrocarbon source rocks in syn-rift sequence, small-scaled post-rift sequence and high-angle basin-controlling major faults etc., and as a result, exhibit petroleum systems with unique characteristics, such as late and long-lasting oil generating window, high oil-expulsion efficiency, and fault-block dominated traps with rare rollovers etc. The deep study and analysis of the basin structure, sedimentary features and petroleum system obviously enhance the exploration discovery of WCARBs, which is the key factor of the successful E&P activities of CNPC in WCARBs.