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Collaborating Authors
Ahmed, Ramy
Abstract New methods used to accurately determine water and hydrocarbon saturation profile, hydrocarbon typing & reservoir extent (connectivity) in real time by using acquired insitu water salinity measurement downhole and measured hydrocarbon optical density from formation testers. The uncertainties present from water salinity (Rw) values from nearby wells (due to vertical & aerial variations) may compute inaccurate hydrocarbon saturations when input in Archie's based fluid saturation model, which affects the hydrocarbon in place calculations. Also, relying only on pressure measurement for connectivity assessment & reservoir extent using Vertical Interference Testing (VIT) may sometimes be misleading & inconclusive due to supercharging in low permeability & low pressure contrast in high permeability which affects the field development plans. Therefore, the new methodology is introduced to overcome these challenges. Firstly, the downhole water salinity is measured in a water zone at the bottom of the reservoir while pumping out using formation tester after achieving clean-out (negligible contamination). The values were input into the initial petrophysical model to recompute the new fluid saturation which was confirmed by pump-out fluid fractions from other zones. Secondly, the optical density measurement from the spectroscopy was used to confirm the vertical connectivity though Reservoir Fluid Geodynamics & indicating a compositional gradient in real time in an oil column. This was done by constructing Flory-Huggins-Zuo (FHZ) Equation of State model and identifying asphaltene molecular size from optical density gradient. These two methods will bring accurate & reliable results compared to conventional methods which has some uncertainties impacting evaluation & reservoir understanding. Secondly, will help in optimizing sampling & downhole fluid analysis programs which eventually saves cost & time & CO2 emissions. Thirdly, Optical Density gradient analysis can be also used for flow assurance prediction.
Integrated Seismic Processing and Geological Identification of the Late Eocene Reservoir Body in Lufeng Block, Pear River Mouth Basin
Li, Li (CNOOC Shenzhen Ltd.) | Ma, Fujian (Schlumberger) | Xu, Chao (CNOOC Shenzhen Ltd.) | Liu, Lianlian (Schlumberger) | Wang, Yaosen (CNOOC Shenzhen Ltd.) | Zeng, Rui (Schlumberger) | Gong, Zijing (Schlumberger) | Liang, Donghai (Schlumberger) | Roy, Dipanka (Schlumberger) | Ahmed, Ramy (Schlumberger) | Saumya, Sachit (Schlumberger)
Abstract The main exploration challenges of the Lufeng Sag, Pear River Mouth Basin (PRMB) area are complex fluvial-deltaic depositional stacking and associated oil-water distributions. The reservoir bodies are buried at approximately 2700 to 3000 m under mud lines, and at these depths the quality of the seismic data is too poor to accurately characterize the reservoirs. The poor seismic quality also results from complex fluvial sedimentation that is overlain by a high-speed limestone layer, as well as deeply buried, thin intervals of interest. In this paper we propose an integrated approach to reprocess the data, increase the imaging quality, and improve the geological understanding of the area. The geology-guided seismic data processing and integrated interpretations, along with seismic inversions, are proved to be a practical solution to improve geologic understanding and help to conduct a drilling campaign for infill wells. The new processed data show improved image quality, including the signal-to-noise ratio and the resolution via noise attenuations, demultiples, and broadband extension processing. Two sedimentation sources are identified with the new data, while the legacy data were vague, and the reservoir layers were interpreted as a single-sourced fluvial-deltaic depositional system. These misleading interpretations do not help us understand the complex oil-water relationship discovered by drilling and failed to locate the sweet spots for future infill wells. However, the new processed data shed light on all the issues and have become a game changer for the area.
- Phanerozoic > Cenozoic > Paleogene > Eocene > Priabonian (0.50)
- Phanerozoic > Cenozoic > Paleogene > Eocene > Bartonian (0.50)
- Geophysics > Seismic Surveying > Seismic Processing (1.00)
- Geophysics > Seismic Surveying > Seismic Interpretation (1.00)
- Geophysics > Seismic Surveying > Seismic Modeling > Velocity Modeling > Seismic Inversion (0.53)
- Asia > China > South China Sea > Zhujiangkou Basin (0.99)
- Asia > China > South China Sea > Pearl River Mouth Basin > Enping Field (0.97)
Innovational Techniques in Utilizing Real-Time Downhole Pressure and Distributed Temperature Surveying for Skin Quantification During Matrix Stimulation in Complex Multilateral Well in Saudi Arabia
Bokhari, Noordeen (Saudi Aramco) | Ghamdi, Talal (Saudi Aramco) | Ahmed, Ramy (Schlumberger) | Al-Dosary, Abdulrahman (Schlumberger)
Abstract This paper describes an innovative workflow for well intervention in a complex multilateral well, not only for accessing each lateral, but also to quantitatively evaluate matrix treatment in real-time for each lateral independently. The quantitative evaluation is based on two simultaneous criterions. The first is derived from the downhole pressure diagnostic plot (pressure transient analysis) in real time using the data acquired by the downhole real time gauge. The second is an estimate of the zonal coverage from the temperature profile plot before, while, and after pumping a treatment. Pressure transient analysis gives the skin as a direct output, and the cooling down/warming up distributed temperature sensing profiles identify where the treatment fluids went into the formation. This approach of combining well testing analysis techniques throughout the treatment in combination with zone coverage evaluation is strongly recommended for horizontal and complex wells, either clastic or non-clastic rocks. Basically, deriving the skin from the injectivity test (pre-treatment) and the skin from the post flush (post-treatment) will give an accurate as well as confident result when evaluating matrix treatments. In a field case, a comparison of the formation damage skin before and after the treatment was performed on the spot, and an improvement of eight times in injectivity was achieved with nearly uniform distribution of treatment fluids across five well laterals. Following the state-of-the-art procedures proposed and executed in this well, we were able to combine different technologies and techniques, which provided measurable cost reduction. The application of the technique will lead to eliminating confusion in accessing well laterals, quantifying the formation damage improvement in real time, eliminating the non-uniform distribution of treatment, optimizing diversion design/placement, and the ability to make treatment changes on the spot.
- Information Technology > Architecture > Real Time Systems (1.00)
- Information Technology > Communications > Networks > Sensor Networks (0.62)
Abstract Increases in well complexity and stimulation challenges have led to more complicated stimulations. The challenge that consistently arises after conceptually designing the treatment is how to determine the zonal coverage and evaluate the stimulation, especially in extended reach wells in carbonate reservoirs. Significant effort has been spent on using modern technologies to qualitatively evaluate zonal coverage and estimate the skin factor evolvement after the treatment. No work has yet answered the following question: How does matrix acidizing alter near-wellbore permeability and affect the zonation of the wellbore when treating carbonate reservoirs? In long horizontal wells that are drilled in carbonate formations, it is believed that wormholing significantly alters the near-wellbore apparent permeability. Nevertheless, methods to estimate the change in permeability resulting from a matrix treatment are not known, and usually the change is accounted for in simulators by assigning a very low skin value. Other work conducted in carbonate reservoirs using pressure transient analysis (PTA) techniques has shown that applying a change in permeability is necessary to obtain a type-curve match. This paper presents an innovative workflow and algorithm to estimate the changes in the critical matrix rock properties and how to incorporate these changes into further simulation. The algorithm integrates the while drilling mobility data, open hole porosity logs, pressure transient data, distributed temperature survey data, and production logging data to verify the accuracy of the model by using the flow rate as the control parameter for iterations. A case study shows how we could derive a flow profile for the pre-stimulation stage, optimize matrix stimulation treatments in real time according to the formation response and diversion efficiency, define reservoir zones that are contributing to flow before and after the treatment, and finally, estimate new values of permeability and skin to be utilized in post-treatment reservoir simulations.
Abstract It is very challenging to measure formation pressure in the low mobility formations of Eastern Desert, Egypt. The measured mobilities ranged from 0.01 to 5 mD/cP; making the acquisition of reliable formation pressure with conventional pretesting very difficult. Many pretests end up being recorded as โDryโ, โTightโ and โSuperchargedโ. However, by exploiting the extreme limits of new generation formation testers such as low volume and relatively lower rates, we were able to overcome these difficulties and record valuable formation pressures. The electromechanically controlled formation tester is specifically engineered for only pressure and mobility testing as opposed to multifunctional formation tester tool that also collects samples. The two important distinctions of this tool are an electromechanically controlled pressure pretest system that enables precise pretest volume and rate. This is in contrast to the hydraulically driven pretest mechanisms in conventional tools. Secondly, because the tool is devoted only to pretesting, it has a very small flowline volume with very tight mechanical construction. The required decompression volume is much smaller than conventional tools, brings new efficiency to the formation pressure testing process by significantly reducing both the time and risk involved with wireline formation testing operation. The operating guidelines is prepared to recognize pressure measurement challenges in low mobility formations, it may assist engineers to identify the problems and take corrective measures by altering pretest volume and rate. Correct practice of taking right volume and rate may bring value to pretests whereas inexperience of pressure measurement in low mobility formations may cause significant damage to the data quality. Herein we have presented examples of good quality pretests changing into โDryโ or โTightโ by taking high volumes and also conversely the โDryโ or โTightโ pretests converting into good quality by optimizing pretest volumes.
- Asia (0.69)
- North America > United States (0.47)
- Africa > Middle East > Egypt (0.35)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Pressure transient analysis (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Open hole/cased hole log analysis (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Formation test analysis (e.g., wireline, LWD) (1.00)
Abstract The Arta fields of Egyptian Eastern Desert are operated by Petrodara, a joint venture of Transglobe Energy and Egyptian General Petroleum Corporation (EGPC). The main producing horizon is the Nukhul and formation pressure measurements are critical in this poorly sorted conglomerated marl in order to understand and model depletion. However, low permeability and high viscosity oils contributed to a very low mobility environment that presented considerable challenges to Wireline Formation Tester (WFT) tools. Extensive testing programs resulted in an excessive amount of tests that were unusable, being classified as โdryโ, โtightโ or โsuperchargedโ. This low mobility environment also complicated the requirement for PVT samples acquired with the WFT tools. Normal testing operations resulted in very high drawdowns that sampled below formation pressure and caused emulsions with the filtrate of the water based drilling fluid. In this paper we discuss how the Operator and the Service Company combined to employ fit for purpose WFT techniques to acquire accurate formation pressure data and PVT quality oil samples. Most of our discussion will be based on understanding the dynamics of pretesting in low permeability formations and how the optimal tool and pretest design can produce results where previous attempts have failed. Specifically we consider the newest โpretest onlyโ WFT that provides very fine control over pretest rate and volume and allows precise test design that is not possible with conventional WFT tools. Additionally, we demonstrate the application of best practices and lessons learned from worldwide sampling operation to acquire PVT quality heavy oil samples.
- Africa > Middle East > Egypt (1.00)
- Africa > Middle East > Djibouti > Arta > `Arta (0.27)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.69)
- Geology > Petroleum Play Type > Unconventional Play > Heavy Oil Play (0.61)
- Africa > Middle East > Egypt > South Sinai Governorate > Lagia Field > Nukhul Formation (0.99)
- Africa > Middle East > Egypt > Gulf of Suez > Gulf of Suez Basin > Rudeis Formation (0.99)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Pressure transient analysis (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Open hole/cased hole log analysis (1.00)
- (2 more...)
Increasing the Efficiency with Wireline Formation Testers and Reducing the Fluid Uncertainties in Thin-Laminated Low Permeability Reservoirs with in the Western Desert, Egypt
Ardila, Mario (Schlumberger) | Ahmed, Ramy (Schlumberger) | Dumont, Hadrien (Schlumberger) | Naguib, Mohamed (Merlon International) | Zabcik, Jim (Merlon International)
Abstract Many sedimentary features of hydrocarbons at Western Desert are characterized as multilayered, deltaic, thinly and tight laminated sandstones consisting of sands with limited lateral and vertical extension. Relying only on conventional openhole log data and performing correlations among nearby wells proved to be inconclusive in identifying hydrocarbons reservoirs owing to their thin beds, high shale content, and variable formation water resistivity. Missing hydrocarbon-bearing formations translates into lost productivity, while perforating water zones can have detrimental effects on well performance. Given these complexities, fluid identification and pressure measurements have a significant impact in resolving key uncertainties of such reservoirs. The main challenges faced during wireline formation testing in the reservoirs studied have been a) laminated, low mobility and thin formations with varying water salinity, b) no representative fluid samples due to deep mud filtrate invasion, c) eventual formation damage while drilling The pretest/sampling efficiency with wireline formation testers and by using single probes has been traditionally very low in thinly laminated reservoirs because of the high possibility of dry or tight tests with long pressure stabilization time and not sampling or high contaminated samples. To displace invade fluids in low permeability formations can be challenging, usually requiring a high drawdown to pump the move filtrate from formation. To improve the job efficiency, High Performance packers and pumps are essentially in such environment that reduce significantly the differential pressure while pumping and increase the envelop to test zones beyond capabilities with the single probes. The Interval Pressure Transient Tests (IPTT) technique has been recently launched to increase the success ratio of wireline formation testers in getting reliable pressures and fluid analysis, including real-time monitoring of each survey by reservoir engineers.
- Africa > Middle East > Egypt (0.86)
- Oceania > Australia (0.69)
- Geology > Geological Subdiscipline > Economic Geology > Petroleum Geology (0.54)
- Geology > Geological Subdiscipline > Stratigraphy (0.48)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.34)
- Africa > Middle East > Egypt > Faiyum Governorate > Fayum Basin > El Fayum Concession (0.99)
- Africa > Middle East > Egypt > Western Desert > Greater Western Dester Basin > Abu Gharadig Basin > Abu Roash Formation (0.94)
- Africa > Middle East > Egypt > Western Desert > Bahariya Formation (0.94)