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Abstract Numerous studies on Formation damage have been conducted, but fewer investigations have been conducted for the ideal diagnosis workflow. More knowledge of geology, reservoir characteristics, and production data is required to identify the source, causes, and best treatment technique for each well's formation damage. In this paper, a workflow for the diagnosis of formation damage is introduced in order to determine the location, potential source, root causes, and recommend a suitable treatment method for the formation damage. The proposed workflow is based on critical steps such as (1) planning and organizing the delivered data for solving the investigated problem, (2) collecting and analyzing all available data, and (3) integrating all geological, reservoir, and production data. Furthermore, the proposed workflow was applied to the Hammam Faraun reservoir in an Egyptian oil field. An integration of available geological, reservoir, and production data was performed in this reservoir to make confident prognosis or diagnoses of formation damage and achieve a complete vision of the sources of formation damage and suggest solutions and treatments. As a result, all aspects of the well and its history were considered when assessing formation damage in the studied well, including core analysis, XRD, mineralogy, water chemistry, reservoir geology, offset well production, reservoir fluids, production history, drilling fluids, cementing program, completion, stimulation, and workover history, and perforation reports. The assessment of the formation damage problem revealed that the suggested workflow was effective and can aid in the detection of formation damage problems throughout the oil and gas wells. The integration of geological, reservoir, and production data resulted in an accurate analysis; two sources of damage could be responsible for the damage in the studied well based on the analysis and integration of geological and engineering data. Firstly, low quality water, secondly the using of an inappropriate stimulation fluid which interact with the existed sensitive formation minerals. Treatment with proper additives is highly recommended in such cases. This work show how can an integrated dataset can be used in the assessment of reservoir damage analysis studies in the studied basin and elsewhere.
- Africa > Middle East > Egypt > Gulf of Suez (1.00)
- Africa > Middle East > Egypt > Suez Governorate > Suez (0.44)
- Phanerozoic > Cenozoic > Paleogene (0.46)
- Phanerozoic > Cenozoic > Neogene > Miocene (0.30)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (1.00)
- Geology > Mineral (1.00)
- Geology > Geological Subdiscipline > Stratigraphy (0.69)
- Geology > Geological Subdiscipline > Geomechanics (0.69)
- Africa > Middle East > Egypt > Gulf of Suez > Gulf of Suez Basin > October Field (0.99)
- Africa > Middle East > Egypt > Gulf of Suez > Gulf of Suez Basin > Morgan Field (0.99)
- Africa > Middle East > Egypt > Gulf of Suez > Gulf of Suez Basin > Kareem Formation > Shagar Member (0.99)
- Africa > Middle East > Egypt > Gulf of Suez > Gulf of Suez Basin > Belayim Formation (0.99)
ABSTRACT: We have interpreted pore pressure and in-situ stress magnitudes of the Miocene-Pleistocene sedimentary succession encountered in the El Morgan oil field, Gulf of Suez Basin, Egypt. Due to prolonged production, the Middle Miocene Hammam Faraun (HF) and Kareem reservoirs are depleted by 870-950 PSI and 1160-1380 PSI, as interpreted from the latest downhole measurements. Based on poroelastic modeling, reduction in minimum horizontal stress was assessed and reservoir stress paths values of 0.61 and 0.66 were inferred in the HF and Kareem sandstones. At a present depletion rate, Kareem formation's stress path is very close to the critical faulting limit inferring a higher possibility of production induced normal faulting in comparison with the HF reservoir. 1. Introduction Reservoir pore pressure and minimum horizontal stress magnitudes are affected by the production induced depletion. In extreme cases, if the rate of change of these two parameters crosses a threshold value/limit, the depleted reservoir can experience depletion-resulted normal faulting and induced seismicity (Addis, 1997; Haug et al., 2018; Koughnet et al., 2018; Radwan and Sen, 2020). A careful assessment of depletion stress path, hence, is critical to infer the stability of a producing reservoir. The El Morgan hydrocarbon field is situated in the Gulf of Suez rift basin, Egypt. This giant field produces hydrocarbon from its Miocene clastic reservoirs belonging to the Hammam Faraun (HF) and Kareem Formations (Radwan, 2021b; Radwan et al., 2021b). Both the reservoirs are characterized by high porosity (~20-26%) and super-high permeabilities (~3000 mD). The last major field development activity was performed in the late nineties and presently both these reservoirs are highly depleted. There has not been any prior publication on the depletion stress path characterization from this giant field, which sets the premise of this work. The principal objectives of this work are: i) interpret the pore pressure and in-situ stress magnitudes in both virgin as well as present-day depleted condition, and ii) characterize the stress paths of the two reservoirs to infer the reservoir stability.
- Africa > Middle East > Egypt > Gulf of Suez > Southern Gulf of Suez (0.26)
- Africa > Middle East > Egypt > Eastern Desert > Southern Province (0.26)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Structural Geology > Fault > Dip-Slip Fault > Normal Fault (0.46)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.37)
- Oceania > New Zealand > North Island > Tasman Sea > Taranaki Basin > Block PMP 38160 > Maari Field > Moki Formation (0.99)
- Oceania > New Zealand > North Island > Tasman Sea > Taranaki Basin > Block PEP 38413 > Maari Field > Moki Formation (0.99)
- Europe > Norway > North Sea > Central North Sea > South Viking Graben > PL 046 > Block 15/9 > Volve Field > Shetland Group > ร sgard Formation (0.99)
- (35 more...)
Abstract Reservoir damage is considered one of the major challenges in the oil and gas industry. Many studies have been conducted to understand formation damage mechanisms in borehole wells, but few studies have been conducted to analyze the data to detect the source, causes, and mitigations for each well where damage has occurred. I have investigated and quantified the reasons and mitigation of reservoir damage problems in the middle Miocene reservoir within the El Morgan oil field at the southern central Gulf of Suez, Egypt. I used integrated production, reservoir, and geologic data sets and their history during different operations to assess the reservoir damage in El Morgan-XX well. The collected data include the reservoir rock type, fluid, production, core analysis, rock mineralogy, geology, water chemistry, drilling fluids, perforations depth intervals, workover operations, and stimulation history. The integration of different sets of data gave a robust analysis of reservoir damage causes and helps to suggest suitable remediation. Based on these results, I conclude the following: (1)ย Workover fluid has been confirmed as the primary damage source, (2)ย the reservoir damage mechanisms could be generated by multisources including solids and filtrate invasions, fluid/rock interaction (deflocculating of kaolinite clay), water blockage, salinity chock, and the high sulfate content of the invaded fluid, and (3)ย multidata integration leads to appropriate reservoir damage analysis and effective design of the stimulation treatment. Furthermore, minimizing fluid invasion into the reservoir section by managing the overbalance during drilling and workover operations could be very helpful. Fluid types and solids should be considered when designing the stimulation treatment and compatibility tests should be performed. Long periods of completion fluid in boreholes are not recommended, particularly if the completion fluid pressure and reservoir pressure are out of balance, as well as the presence of sensitive formation minerals.
- Africa > Middle East > Egypt > Gulf of Suez (1.00)
- Africa > Middle East > Egypt > Suez Governorate > Suez (0.63)
- Geology > Mineral > Silicate (1.00)
- Geology > Geological Subdiscipline (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.90)
- Africa > Middle East > Egypt > North Sinai Governorate > Southern Levant Basin > Halal Field (0.99)
- Africa > Middle East > Egypt > Gulf of Suez > Gulf of Suez Basin > October Field (0.99)
- Africa > Middle East > Egypt > Gulf of Suez > Gulf of Suez Basin > Morgan Field (0.99)
- (4 more...)
Stress Path Analysis of the Depleted Middle Miocene Clastic Reservoirs in the Badri Field, Gulf of Suez Rift Basin, Egypt
Radwan, Ahmed E. (Faculty of Geography and Geology, Institute of Geological Sciences, Jagiellonian University, Krakรณw, Poland) | Sen, Souvik (Geologix Limited, Mumbai, Maharashtra, India)
Abstract The purpose of this study is to evaluate the reservoir geomechanics and stress path values of the depleted Miocene sandstone reservoirs of the Badri field, Gulf of Suez Basin, in order to understand the production-induced normal faulting potential in these depleted reservoirs. We interpreted the magnitudes of pore pressure (PP), vertical stress (Sv), and minimum horizontal stress (Shmin) of the syn-rift and post-rift sedimentary sequences encountered in the studied field, as well as we validated the geomechanical characteristics with subsurface measurements (i.e. leak-off test (LOT), and modular dynamic tests) (MDT). Stress path (ฮPP/ฮShmin) was modeled considering a pore pressure-horizontal stress coupling in an uniaxial compaction environment. Due to prolonged production, The Middle Miocene Hammam Faraun (HF) and Kareem reservoirs have been depleted by 950-1000 PSI and 1070-1200 PSI, respectively, with current 0.27-0.30 PSI/feet PP gradients as interpreted from initial and latest downhole measurements. Following the poroelastic approach, reduction in Shmin is assessed and reservoir stress paths values of 0.54 and 0.59 are inferred in the HF and Kareem sandstones, respectively. As a result, the current rate of depletion for both Miocene reservoirs indicates that reservoir conditions are stable in terms of production-induced normal faulting. Although future production years should be paid more attention. Accelerated depletion rate could have compelled the reservoirs stress path values to the critical level, resulting in depletion-induced reservoir instability. The operator could benefit from stress path analysis in future planning of infill well drilling and production rate optimization without causing reservoir damage or instability.
- Asia (1.00)
- Africa > Middle East > Algeria > Ouargla Province > Hassi Messaoud (0.28)
- Africa > Middle East > Egypt > Gulf of Suez > Southern Gulf of Suez (0.25)
- Africa > Middle East > Egypt > Eastern Desert > Southern Province (0.25)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.77)
- Geology > Structural Geology > Fault > Dip-Slip Fault > Normal Fault (0.56)
- Oceania > Australia > Tasmania > Bass Strait > Gippsland Basin (0.99)
- North America > United States > Texas > Travis Peak Formation (0.99)
- North America > United States > Mississippi > Travis Peak Formation (0.99)
- (23 more...)
Abstract The complex depositional, burial, and diagenetic histories of the Late Cretaceous Nezzazat Group sandstones in Northeastern Africa present the main challenges with regard to reservoir quality. The quality of commercial reservoirs is maintained despite deep burial and the associated high temperature and pressure. The study presents an optimum integration of different data sets to address reservoir quality and reservoir performance controllers. The data set includes measured porosity and permeability, petrographic point-counting data, grain-size analysis, X-ray diffraction data, scanning electron microscopy, and porosity loss by compaction. The depositional controls on the reservoir quality are the facies, whereas the higher quality is found in the channel and upper shoreface settings. The coarse-grained sandstone is associated with better reservoir quality. The large intergranular porosity is the main porosity controlling the fluid flow. The massive and laminated sandstones are the best quality facies. The labile grains (feldspars and mica) control the permeability distribution. Whereas the secondary diagenetic controllers are the carbonate cementation that inhibited the effects of compaction. The siderite cementation has resulted in a micropore dominated and highly tortuous pore system. Total porosity has largely been preserved in the siderite-cemented sample but virtually eliminated in the dolomite cemented. A low volume of illite is associated with better reservoir quality. Whereas the better reservoir quality is associated with the abundant quartz cementation that protected the primary porosity from compaction. Compaction acts as a significant porosity loss factor during diagenesis. Authigenic kaolinite does not significantly affect the reservoir quality. The reservoir sensitivity to formation damage comes from the potential for fines (kaolinite, illitic clays, siderite, and pyrite) migration within the pore system that is readily mobilized by the fluid flow.
- Asia > Middle East > Saudi Arabia (1.00)
- Africa > Middle East > Egypt > Gulf of Suez > Southern Gulf of Suez (0.40)
- Africa > Middle East > Egypt > Eastern Desert > Southern Province (0.40)
- Geology > Sedimentary Geology (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (1.00)
- Geology > Mineral > Silicate > Phyllosilicate (1.00)
- Oceania > New Zealand > North Island > Tasman Sea > Taranaki Basin > Maui Field (0.99)
- Oceania > New Zealand > North Island > Taranaki Basin (0.99)
- North America > United States > California > Ventura Basin (0.99)
- (5 more...)