Some heavy oils reservoirs present an unusual behavior when put on production under significant drawdown conditions. In these reservoirs, the high formation depressurization increments the recovery factor and accelerates the production rates driven by a solution gas mechanism. Due to the chemical and physical properties of these oils they tend to stabilize the dispersion of gas bubbles, promoting the generation of foam in the oleic phase. This foamy oil when compared with conventional oils result in a more productive response at similar drawdown conditions. The foamy oil phase behavior is the result of a number of complex mechanisms and requires a good understanding on each of them to estimate the potential response of these reservoirs. In this work, the role of key factors that affect the bubbly oil production is summarized.
To outline the significance of key variables on the performance, a commercial optimization and uncertainty analysis software coupled with a mechanistic simulator is used. The simulator allows a detailed modeling of the physics involved on the generation and behavior of the foamy oils, in which the foamy oil is modeled as a disperse phase of gas bubbles in the oleic phase, including small mobile gas bubbles and larger trapped gas bubbles flowing as discontinuous gas dispersion which affect foam viscosity, compressibility, mobility and relative permeability. Fluid properties used in this work are from
The sensitivity and optimization analysis performed in this work on key reservoir variables and well operational parameters shows the significance of each factor on the production response. The relative importance of each variable is reported in tornado diagrams. Results showed that a strong approach on handling the reservoir unknowns are as crucial as the control of operational parameters from reservoir management point of view.
Nowadays the foamy oil behavior and its favorable production response are not totally well understood. Solutions have been proposed but they are still controversial and the use of horizontal wells introduces more complexity in the production operations. In this work is provided an in-depth optimization and uncertainty analysis to outline the role of each major parameter affecting the production response and the recovery efficiency in this type of reservoirs using horizontal wells.
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).
Liu, Bingshan (CNPC Drilling Research Institute) | Wang, Xi (CNPC Drilling Research Institute) | Tu, Apeng (CNPC) | Zhang, Shunyuan (CNPC Drilling Research Institute) | Jiang, Zi (CNPC Drilling Research Institute) | Fu, Jin (CNPC Drilling Research Institute)
Most area of North Azadegan oilfield is covered by wetland, especially, in the north part it is covered by reed marshland with 1.5-3m deep water. Meanwhile, there are lots of landmines left during the Iran-Iraq war. It is expensive to construct pads in this area (more than 300 million dollars for one pad). In order to protect environment, decrease dangers to construct pads and save cost on building pads, cluster well is the first choice.
In this paper, well network was optimized first based on geological requirements and environment limits. Formations upper 800m are unconsolidated, 800m-1000m mainly are shale and more stable, Gachsaran contains bout 1800m salt-gypsum in lower part with high formation pressure about 1.8g/cm3 and high pressure salt aquifer with EWD up to 2.31g/cm3. Two plans for kick off point of horizontal wells were considered, in the interval 800-1000m or below Gachsaran. Multi-well anti-collision and avoidance of obstacle were considered and the well profiles were optimized.
15 well pads for cluster wells were designed: 5 pads with 5 horizontal wells, 1 pad with 5 horizontal wells and 1 vertical well, 1 pad with 4 horizontal wells and 8 pads with 2 horizontal wells. This protects environment and saves cost expending on pads building to the maximum extent. After considering effects of KOP on dogleg and inclination and the downhole complications encountered in drilled wells comprehensively, kick off point was built in Gurpi formation about 2300m deep (below Gachsaran). Based on this, optimized the wellbore trajectory, BHA and parameters. By far, all the wells planed have been finished, there is no any collision accident, target hitting rate is 100%, drilling catching rate in reservoir is 100%, both the success rates of electric logging in horizontal interval and casing running in designed depth are 100%.
The drilling experience and expertise in north Azadegan oilfield could be used for a beneficial technical reference for drilling in such complicated environment and complicated formations.
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.
Oil production in presence of a bottom aquifer is one of the most challenging issues in reservoir engineering. In most cases water coning happens very quickly and the influx of water restricts oil production and limits recovery. The problem is even more difficult when the oil is heavy because the viscosity contrast is large. In some cases horizontal wells may be used to improve the situation but when reservoirs are thin and the oil is viscous even horizontal wells are of limited use. This paper presents the challenges and potential solutions for Enhanced Oil Recovery in heavy oil reservoirs with bottom aquifer. Existing literature is reviewed for field cases of EOR experience with bottom aquifer for chemical as well as thermal processes (SAGD, steam injection as well as In Situ Combustion). In the case of chemical EOR the chemicals may be lost to the aquifer; for thermal recovery the bottom water can act as a heat sink and affect and steam oil ratio. Some in-situ combustion projects have been successful in such settings but in every case the outcome is the same: the economics of the project can be affected. The paper contains some previously unpublished data of polymer injection in a heavy oil pool with some limited bottom aquifer; for the most part it is a review of the existing literature which may prove useful to practicing engineers who are faced with the issue of developing heavy oil resources in the presence of bottom aquifer.
Wu, Yongbin (PetroChina Co. Ltd.) | Li, Xiuluan (Research Inst. Petr. Expl/Dev) | Liu, Shangqi (Research Inst. Petr. Expl/Dev) | Ma, Desheng (Expl & Dev Rsch Inst Liaohe Co.) | Jiang, Youwei (Research Inst. Petr. Expl/Dev)
Thermal recovery technology particularly cyclic steam stimulation (CSS) is always an effective means to develop the conventional heavy oil reservoirs, which can be validated from literature. While most of the heavy oil reservoirs developed by CSS are the thick, well-deposited, high quality reservoirs and there are no much reports of producing oil from mid-depth oil reservoirs with large acquifers.
In this paper, according to the petrophysical properties and geologic characteristics of the target block F in Greater Fuld oilfield in Sudan, based on the oil test results, detailed 3D geologic model is established and the type well model for CSS and SF is extracted, to study the real performance with the real geological properties.
The development zone, the perforation strategies, the cylic steam injection quantity, the steam injection rate, soak time, and cyclic period are optimized for CSS. Based on the production performance of CSS, the optimal cycles of CSS followed by SF is determined. And the wellpattern and well spacing, the parameters of SF such as unit steam injection rate, steam quality, effects of bottom acquifer on the SF are also simulated and optimized. The simulation results indicate that the thermal recovery technique especially 4 cycles of CSS followed by SF can acquire satisfied performance, which shows an effective and economic future in the development of the heavy oil deposits in Greater Fula Oilfield.
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.
As we know, sand production can bring about both positive and negative effects. For example, besides borehole problems, sand production can improve the porosity and permeability of reservoirs. This is why the strategy to handle sanding problems can vary from stimulating sand production to sand control. So far, the industry has developed all kinds of sand management technologies, including treatments both on surface and downhole.
When we meet sand production problems in oil field development, we need to find a solution based on certain of sand management technologies. Conventionally, we conduct an analysis on sand production reasons and possibilities first, and then we pick a technical solution from some known technical alternates. However, generally, it is difficult to tell which option is the best, because when we make a technical decision, the main factor or even the only factor we take into consideration is the technical feasibility or technical advantages of a system. Some operators like to use high-tech solutions, some like to use normal ones. High-tech does not mean definitely to bring a bigger benefit than normal-tech. Unless we have compared the economic benefit of each technical solution within a given term, we cannot tell which one is the best solution.
Economic evaluation model (EEM) for sand management tech selection is seldom discussed in previous references. This paper launches an independent EEM that can help us select the sand management solution by economic benefit evaluation instead of by technical factors solely. Factors related to the model are detailed in the paper. Examples are given to show how to use the model.
In addition, some common issues in sand prediction models are discussed herein, suggestions on how to improve the models given. The paper believes the classification of sanding severity is quite necessary. A classification of sanding severity is proposed.
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.