This paper demonstrates an innovative clusterization approach to define development strategy for small and scattered fields in T Basin, which is located in landlocked central Africa. As a rifted basin, T basin is around 250 km long and 80 km wide under sub-Saharan desert environment. The operator started exploration in 2008 and had discovered over 40 oil fields scattered over the whole basin but with limited size. 30 small oilfields occupy only 20% of total OOIP. Therefore the discovered fields in T basin belong to small and scattered fields. To realize fast track development in landlocked desert and achieve economic robustness meanwhile is the huge challenge for the operator. Clusterization development strategy had been put forward to realize integrated asset development.
Clusterization is to define several oil field clusters based on the criteria of adjacency, reservoir characteristics etc. Each oil field cluster should have one and/or two relatively bigger oil field as the central fields. Satellite fields are grouped into adjacent central fields thus forming oil field clusters. The whole basin development optimization could be carried out on a two-tier level: 1) for the intra cluster level, central fields will be commissioned first and satellite fields could be ranked to substitute production plateau, satellite fields facilities could be skid-mounted and shared among satellite fields to reduce Capx. 2) for the oilfield cluster level, clusters could be ranked according to criteria of OOIP scale, productivity projection and commissioning complexity. Relatively concentrated oilfield clusters could be prioritized to arrive at long term production projection. The remaining clusters could serve as plateau maintenance purpose afterwards.
Five oilfield clusters had been defined under the guidance of clusterization strategy. Three oilfield clusters had been recommended for Phase I production after optimization on the inter-cluster and intra-cluster level. 60 KBOPD of productivity with longer plateau is expected from clusterization development with convincing economical parameters, which fully satisfy the requirement of long distance pipeline.
This paper had proposed an innovative clusterization approach to define development strategy for small and scattered oilfields in a landlocked basin. The two-tier optimization process inherent in the clusterization approach could be of strong reference value to similar marginal blocks and basins.
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).
Deep formation damage caused by killing fluid frequently occurs in blowout wells and clean-up operations may result in early water breakthrough and less hydrocarbon recovery. This paper presents three innovative practices applied in oil and gas wells that suffered blowout accidents for more hydrocarbon recovery. i.e.:
These methods have been successfully utilized in more than 40 wells for over 50 years. The three typical field examples are illustrated. One of them is an oil well in sandstone reservoir, with double oil rate as the nearby wells. The rest are a gas well in massive carbonate pool with bottom water, with the most prolific gas production in the field, and a gas well in a naturally fractured reservoir, with Gp of over 180 BCF.
Each year tens of thousands of oil and gas wells are successfully drilled worldwide. The overall safety record of the drilling and workover operations is quite satisfactory. On occasion, however, blowout problems can arise during drilling and workover where the control of a well is lost, whenever a well begins to flow uncontrollably.
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.
This paper demonstrates an innovative in-situ natural gas lifting approach, which has been successfully applied in AG pool of FN field, Sudan. AG pool is a series of edge water driven stacked sandstones with light oil and natural gas pools, and mostly natural gas zones are below oil zones. AG oil is typical of high pour point, ranging from 37 to 57 Celsius degree. Possibility of wax deposition posed great production and operational challenges at 27 Celsius degree surface temperature. Gas below oil pool could serve as in-situ gas lifting to boost production and reduce wax deposition. This process undergoes tubing produced natural gas flowing simultaneously into annular to lift oil production in the same wellbore. This process has been optimized by following approaches: 1) establishing screening criteria of qualified gas and oil zones for lifting; 2) Partial completion and reduced perforation density in gas zones for controllable gas rate; 3) Separators deployed to remove portion of gas for smooth transportation to facilities.
4 producers have undergone in-situ gas lifting since 2009, average well output achieved 2 to 4 times of DST rate, amounting to 2000 to 4000 BOPD with low water cut. Up-efficiency has been above 85% without wax deposition problems. Operational costs were greatly reduced. Conclusions drawn from successful in-situ gas lifting application were:1) selected oil and gas zones fully qualified for gas lifting; 2) optimized in-situ gas lifting brought high output and low water cut; 3) innovative wellbore structure and facilities design replaced the use of pumps and saved costs.
Sudan is abundant in stacked oil and gas pools with high pour point, therefore in-situ gas lifting has wide applications.
Successful in-situ gas lifting in this paper highlighted significant oil rate gain without oil gelling problems, cost-effective wellbore structure and facilities design, give a staircase for future wider applications.
Wang, Ruifeng (RIPED, PetroChina) | Yuan, Xintao (RIPED, PetroChina) | Tang, Xueqing (Petro-Energy E&P Co., Ltd.) | Wu, Xianghong (China Natl. Petroleum Corp.) | Zhang, Xinzheng (RIPED, PetroChina) | Wang, Li (RIPED, PetroChina) | Yi, Xiaoling (RIPED, PetroChina)
This paper demonstrates application of Cold Heavy Oil Production with Sand (CHOPS) in Sudan, which has been successfully applied in B heavy oil reservoir of FN field. B reservoir is a series of massive sandstones with strong bottom water drive, which are loosely consolidated and interbedded with shale barriers. Burial depth is 1250 m, average net pay thickness is 35 m. In-situ viscosity is around 300 mPa.s. Cold production well tests indicated average productivity of 500 BOPD, 2-3 times of sand controlled productivity. Global heavy oil fields with successful CHOPS histories have been investigated to confirm applicability in B reservoir and identify two major challenges of CHOPS application in B reservoir: 1) arresting rapid bottom water coning; 2) managing sand production in borehole and surface. CHOPS production strategy has been optimized by following approaches: 1) perforation ratio optimization based on fine barriers (interbed/ intrabed) characterization and numerical simulation to avoid rapid coning; 2) borehole PCP lifting and surface de-sanding facilities optimization for sand control.
70 producers have been commissioned from 2004 to 2006 with optimized perforation ratio of 30% (total net pay), water cut has been kept below 10% with 2% annual offtake rate. Since 2007, 40 infill wells inclusive of horizontal wells have been drilled to further suppress water coning. Recovery factor to date is 13% with WCT of 46% as of 2010, demonstrating better performance than similar heavy oil reservoirs. Producers' up-efficiency has been kept above 85%. Conclusions drawn from successful CHOPS application in B reservoir were as follows:1) optimized perforation contributed to low water cut in early stage; 2) infill well beneficial to suppressing WCT in middle stage; 3) optimized lifting and facilities contributed to high production up-efficiency.
Heavy oil reserves takes 40% of Sudan's total reserves, therefore CHOPS has wide applications for similar Sudanese and African fields.
Successful CHOPS in this paper highlighted fine barriers (interbed/ intrabed) characterization and optimized perforation strategy, infill well drilling, optimized borehole lifting and facilities design, giving a cost-effective staircase for CHOPS implementation.
Wang, Ruifeng (RIPED, PetroChina) | Wu, Xianghong (China Natl. Petroleum Corp.) | Yuan, Xintao (RIPED, PetroChina) | Wang, Li (RIPED, PetroChina) | Zhang, Xinzheng (RIPED, PetroChina) | Yi, Xiaoling (RIPED, PetroChina)
This paper demonstrates the first cyclic steam stimulation (CSS) pilot test in Sudan, which was applied in FNE shallow heavy oil reservoir. B reservoir of FNE field is a shallow, heavy oil reservoir with strong bottom water, burial depth is 520 m. Well tests have shown low oil rates under cold production, averaging at 50-150 BOPD. Denser well spacing will be required if under cold production, which will be quite cost consuming. CSS generally could yield enhanced oil for heavy oil reservoirs. Therefore CSS pilot test has been planned by approaches as follows: 1) investigation of global heavy oil fields with successful CSS histories to confirm applicability in FNE field; 2) Pilot well screening criteria establishment based on sedimentary and reservoir engineering analysis; 3) Perforation optimization to avoid rapid coning based on thermal simulation; 4) steam injection parameters optimization; 5) applicability of natural gas as cost-effective heating source.
CSS Pilot tests on two wells began in 2009. Convincible results have been monitored with well daily rates 3-4 times of cold production wells with low water cut. Another six CSS wells further came on stream from July. 2010, achieving similar positive results. Conclusions drawn from pilot test were as follows: 1) Optimized perforation contributed to low water cut; 2) steam injection density was optimized around 120 t/m; 3) Natural gas as heating source greatly reduce operating cost.
Heavy oil reserves are estimated to take 40% of Sudan's total reserves. Sudan is also abundant in natural gas reserves, therefore cost-effective CSS development strategy has wide applications for similar Sudanese and African fields.
Successful CSS pilot test in this paper highlighted CSS well screening criteria, perforation strategy, steam injection optimization and natural gas utilization, giving a cost-effective staircase for CSS pilot design and implementation.
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.
The Kenkiyak pre-salt oil field is a heavy oil reservoir with the average porosity of 36.6%, the average permeability around 1875x10-3µm2, the buried depth between 290~380 m, the dead oil viscosity within 144~691mPa.s @20oC, the reservoir temperatures between 18.8~20oC. From 1967 to 2002, the reservoir was developed by depletion. As a result, the average reservoir pressure has dropped from 5.9Mpa to 1.8 MPa. The serious heterogeneous characteristics and rapid water invasion made the water-cut of wells as high as 76%. Furthermore, the average well production rate declined from the original 8 m3/d to the later 1~2m3/d., and was staying at this level for a long time. The field was hovering at the economical margin in 2002. In 2003, the operator launched a series of studies and pilot tests to improve the production performance and economic benefits. But there is no proven current recovery technique that can be economically applicable to such viscous oil reservoirs. However, there are huge amount of hydrocarbon accumulation in such reservoirs that can only be exploited with new concepts. Superheated steam huff and puff as a superior technology for the recovery of high water-cut heavy oil reservoirs has been pilot tested in Pre-salt oil reservoir and has found satisfactory development results. This work introduces this new recovery technique of superheated steam huff and puff to effectively develop serious water-invaded heavy-oil reservoirs, and reviews the main practices we have performed, including simulation studies, pilot tests, challenges encountered and solutions, and current effects. Valuable knowledge and experiences have been obtained in terms of superheated steam huff and puff in such reservoirs after many years depletion development, providing reliable operational experience and technical support for Kenkiyak pre-salt reservoir and similar oilfields.