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Abstract The need to develop new tools that allow reservoir engineers to optimize reservoir performance is becoming more demanding by the day. One of the most challenging and influential problems facing reservoir engineers is well placement optimization. The North Kuwait field (NKF) consists of six fields containing four naturally fractured carbonate formations. The reservoirs are composed of relatively tight limestone and dolomite embedded with anhydrate and shale. The fields are divided into isolated compartments based on fault zones and supported by a combination of different fluid compositions, initial pressures, and estimated free-water levels. Due to natural complexity, tightness, and high drilling costs of wells in the NKF, it is very important to identify the sweet spots and the optimum well locations. This paper presents two intelligent methods that use dynamic numerical simulation model results and static reservoir properties to identify zones with a high-production potential: reservoir opportunity index (ROI) and simulation opportunity index (SOI). The Petrel* E&P software platform was chosen as the integrated platform to implement the workflow. The fit-for-purpose time dependent 2D maps generated by the Petrel platform facilitated the decision-making process used for locating new wells in the dominant flow system and provided immense support for field-development plans. The difference between the two methods is insignificant because of reservoir tightness, limited interference, and natural uncertainty on compartmentalization. At this stage, pressure is not a key parameter. As a result, unlike brown fields, less weight was given to simulated pressure, and SOI was used to select the well locations. The results of this study show that implementing these workflows and obtaining the resulting maps significantly improve the selection process to identify the most productive areas and layers in a field. Also, the optimum numbers of wells using this method obtained in less time and with fewer resources are compared with results using traditional industry approaches.
- Asia > Middle East > Kuwait > Jahra Governorate > Arabian Basin > Widyan Basin > North Kuwait Jurassic (NKJ) Fields > Marrat Formation > Upper Marrat Formation (0.98)
- Asia > Middle East > Kuwait > Jahra Governorate > Arabian Basin > Widyan Basin > North Kuwait Jurassic (NKJ) Fields > Marrat Formation > Sargelu Formation (0.98)
Abstract Resistivity measurements play a key role in hydrocarbon in place calculations for oil and gas reservoirs. They are a direct indicator of fluid saturation and connected pore space available in the formation. Carbonate rocks, which host around half of the world's hydrocarbons, exhibit a wide range of porosities with scales spanning from nanometres to centimetres. The often significant amount of microporosity displayed by Carbonate rocks emphasizes the necessity of an adequate characterization of their micro-features and their contribution to hydrocarbon in place. In this paper we examine upscaling methods to probe formation factor of a fully saturated carbonate sample using an X-ray CT based numerical approach and compare to experimental measurements. Three-dimensional high-resolution X-ray CT enables the numerical calculation of petrophysical properties of interest at the pore scale with resolutions down to a few microns per voxel. For more complex and heterogeneous samples however, a direct calculation of petrophysical properties is not feasible, since the required resolution and a sufficient field of view cannot be obtained simultaneously. Thus an integration of measurements at different scale is required. In this study a carbonate sample of 38mm in diameter is first scanned using the X-ray CT method with a resolution of 26 µm. After accompanying experimental measurements on the full plug, four 5mm plugs were drilled vertically from this sample and X-ray CT images of these plugs acquired at resolutions down to 2.74 µm. We calculate the porosity of the sample (macro- and micro-porosities) using the phase separation methods and then predict the formation factor of the sample at several scales using a Laplace solver. The formation factor is calculated by using a general value of m=2 as cementation factor for intermediate porosity voxels. We compare to experimental measurements of formation factor and porosity both at the small plug and full plug scale and find good agreement. To assess the degree of uncertainty of the numerical estimate, we probe the extent of heterogeneity by investigating the size of a representative elementary volume (REV) for formation factor. We find that for the considered heterogeneous carbonate sample, formation factor varies considerably over intervals less than a centimetre. Our results show that this variation could be explained by different cementation exponents applied at the micro-voxel scale, with the exemption of one plug, for which the cementation exponent would have to be unreasonably low. These cementation factors are derived by direct comparison between numerical simulation and experiment. We conclude that for one plug an error in experimental measurement might have occurred. The numerical approach presented here therefore aids in quality control. Excluding this plug in the upscaling procedure improves the agreement with the experimental result for the whole core while still underestimating formation factor. Allowing for a constant m=2 in the simulation at the small scale and using directly the resulting relationship between porosity and formation factor in the upscaling process leads to an overestimation of formation factor.
- North America > United States > Texas (0.46)
- Asia > Middle East > Saudi Arabia (0.28)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (26 more...)
Abstract During recent years there has been a significant increase in the use of filter cake removal systems that involve in-situ release of formic or lactic acid during the clean-up stages of the reservoir section, particularly in limestone formations. Furthermore, there have been opportunities to compare the field performance of these relatively small applications of weak, organic acids with significantly larger application volumes of highly concentrated hydrochloric acid (HCl). Surprisingly, some results showed that the smaller volumes of the weaker, organic acids could have equivalent or better performance than that produced by the more traditional HCl-based treatments. In particular this relationship was also observed in cases where the volume of HCl applied had significantly greater power to dissolve limestone than was the case for treatment with the more successful organic acid. It is well known that productivity of wells in carbonate reservoirs is usually greatly improved by treatments designed to remove the filter cake and the low-permeability zone created by the drilling process, but it is not obvious why smaller volumes per foot of weak organic acid should be more effective than larger volumes per foot of stronger and more concentrated mineral acid. It has been observed that the acid precursors which release the in-situ acids are applied to the formation in a neutral condition. The paper discusses the implications of using neutral acid precursors, and laboratory data is presented showing the effects of such treatments on the near-wellbore matrix permeability.
- Asia > Middle East > Kuwait (0.29)
- Asia > Middle East > Qatar (0.28)
- Asia > Middle East > Qatar > Arabian Gulf > Arabian Basin > Arabian Gulf Basin > Block 6 > Al Khalij Field > Mishrif Formation (0.99)
- Asia > Middle East > Kuwait > Ahmadi Governorate > Arabian Basin > Widyan Basin > Umm Gudair Field > Marrat Formation > Sargelu Formation (0.99)
- Asia > Middle East > Kuwait > Ahmadi Governorate > Arabian Basin > Widyan Basin > Umm Gudair Field > Marrat Formation > Najmah Formation (0.99)
- (4 more...)
Abstract Polymer Gel Injection is an efficient method for Water Shut-Off (WSO) application in naturally fractured carbonate oil reservoirs with high water cuts. The application of WSO extends the economic life of the field is extended with the decline in water production. Polymer gel injection has become a common application to remediate high water rates in fractured networks replacing the usual procedures of squeeze cementing, landing open-hole packers, and liners. A well selection procedure is developed for a successful WSO treatment in a given field which is based on the analysis of reservoir rock and fluid properties and production history of the field. The best candidates of wells are chosen with respect to; estimated remaining mobile hydrocarbons in place, productivity index (PI) values, number of fracture intensity, completion types and water cut of the wells. Then, the effects of WSO application simulations run for water-shut-off polymer gel injection application for the selected wells on oil recovery comparison. Finally, application economics for the selected wells are studied for the justification of procedure. In the candidate field the results showed that the wells having high PI values with high fracture density distributions (number of fractures) located on the apex of the field were the good candidates. Also, the wells, having low cumulative oil recovery with high water cut %, completed as a cased hole or short pay zone under the casing (open hole) were the verified well candidates with the field simulator, for WSO polymer gel application in the field. Consequently, the results of simulations showed that the treatment was economically more profitable.WSO treatment in candidate field was resulted in immediate payout in 60 days. The selected five wells, after the application gave 2.77 profits to investment ratio at the end of ten months production period with an incremental oil recovery of 15.763 bbls.
- North America > United States > Oklahoma (0.29)
- Asia > Middle East > Turkey (0.28)
- Europe > United Kingdom > Scotland (0.28)
- Geology > Geological Subdiscipline (0.54)
- Geology > Rock Type > Sedimentary Rock (0.47)
- Geology > Petroleum Play Type (0.46)
- North America > United States > Utah > Ashley Valley Field (0.99)
- North America > United States > New Mexico > Permian Basin > Dagger Draw Field (0.99)
- Asia > Middle East > Turkey > Raman Field (0.99)
Impact and Lessons of Using High Permeability Streaks in History Matching a Giant Offshore Middle East Carbonate Reservoir
Brantferger, K. M. (Zakum Development Company (ZADCO)) | Kompanik, G. S. (Zakum Development Company (ZADCO)) | Al-Jenaibi, H. M. (Zakum Development Company (ZADCO)) | Dodge, W. S. (Zakum Development Company (ZADCO)) | Patel, H.. (Zakum Development Company (ZADCO))
Abstract A new generation geologic model for a giant Middle East carbonate reservoir was constructed and history matched with the objectives of creating a model suitable for full field prediction and sector level drill well planning. Several key performance drivers were recognized as important factors in the history match; 1) unique carbonate fluid displacement; 2) data validation and horizontal well trajectory issues; and 3) distribution of high permeability streaks. Ultimately a full field history match consisting of more than 1000 well strings and several decades of history was achieved using detailed distribution of the high permeability streaks, while honoring measured core poro-perm relationships, lab-validated displacement curves, and well test data. This paper discusses the role of the geometry and the vertical distribution of the high-permeability streaks in the history matching of a giant offshore carbonate reservoir. Specifically, the modeling of the high-permeability streaks – which consist of thin rudist and algal rudstone, floatstone, and peloidal grainstone, with abundant, well-connected inter-particle porosity - became possible after extensive revamping of the reservoir rock type model, updating well descriptions, and a detailed zonal mapping of the high permeability streaks and dolomitic zones. The areal and vertical model resolution was doubled over the previous models to accommodate the internal sub-layering of the upper four reservoir zones in order to capture the thin (~1.4 ft) high-permeability streaks. During the history match, local modifications of the high-permeability streaks were the integral part of the feedback loop between the simulation engineers and geoscientists that kept the common-scale simulation model and geologic model synchronized. The final history match was validated by extensive analysis of the models’ vertical conformance as compared to production logs. This approach made it possible to construct a more heterogeneous model than previous models; while honoring both field KH and matrix poro-permeability without local permeability multipliers. The combination of these features provides a higher confidence model of long term well injectivity/productivity.
Abstract A project study has been performed in order to evaluate a number of reservoir characterization and petrophysical parameters using Digital Rock Physics (DRP) technology in complex carbonate reservoir, on-shore Abu Dhabi. High-resolution images (X-ray micro-tomographic) of the rock's pores and mineral grains were obtained, processed and the rock properties were evaluated by numerical simulation of the physical processes of interest at the pore scale. The selection of core samples in carbonate reservoir was performed with considering reservoir rock type, logs and routine core analysis data for validation and application phase. A set of special core analysis (SCAL) data were acquired earlier on the core samples in different carbonate reservoir rock types of varying levels of heterogeneity, lithology, porosity, and absolute permeability. This set of measurements formed the baseline for our validation study, then similar DRP approach and improvement is applied for non-SCAL cores. This process is used in DRP study to evaluate cementation exponents ‘m’, saturation exponents ‘n’, water-oil relative permeabilities, capillary pressures and elastic parameters such as compressional/shear wave velocities. An integration of core and logs data in particular carbonate reservoir has been used to provide accurate and reliable results in the validation phase of DRP. It has been observed in DRP that connected micrite phase conductivity contribution has been determined for improvement approach by assigning a finite conductivity σmic to the micrite phase to get reliable formation factor, cementation and saturation exponent. DRP and core J-capillary were integrated to provide reliable saturation-heights in this carbonate reservoir. The integration of formation evaluation in this case study has provided improvement, reliability in DRP results for formation evaluation and the potential to improve the quality and timeliness of carbonate reservoir characterization.
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geophysics > Borehole Geophysics (1.00)
- Geophysics > Seismic Surveying (0.89)
- Asia > Middle East > Saudi Arabia > Thamama Group Formation (0.98)
- Asia > Middle East > UAE > Thamama Group > Shu'aiba Formation (0.89)
- Asia > Middle East > UAE > Abu Dhabi > Rub' al Khali Basin > Habshan Field > Thamama Group > Habshan Formation (0.89)
- (2 more...)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Carbonate reservoirs (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Core analysis (1.00)
Developing High Resolution Static and Dynamic Models for Waterflood History Matching and EOR Evaluation of a Middle Eastern Carbonate Reservoir
Masalmeh, S. K. (Shell Technology Oman) | Wei, Lingli (Shell China Innovation and R&D) | Hillgartner, H.. (Shell Technology Oman) | Al-Mjeni, R.. (Shell Technology Oman) | Blom, C.. (Shell Technology Oman)
Abstract Enhanced oil recovery (EOR) has become increasingly important to maintain and extend the production plateaus of existing oil reservoirs. Simulation models for EOR studies require the right level of spatial resolution to capture reservoir heterogeneity. Data acquired from the dedicated observation wells are essential in defining the required resolution to capture reservoir heterogeneity. For giant reservoirs with long production history, their full field models usually have grid block sizes that are of similar scale as the distance between injectors and observation wells, with the consequence of losing the value of the time lapse saturation logs from dedicated observation wells. Therefore, using high resolution sector models, especially from the part of the reservoir where static and dynamic data sets are rich, is a must. The objective of this paper is to present an improved and integrated reservoir characterization, modelling and water and gas injection history matching procedure of a giant Cretaceous carbonate reservoir in the Middle East. The applied workflow integrates geological, petrophysical, and dynamic data in order to understand the production history and the remaining oil saturation distribution in the reservoir. Large amounts of field data, including time lapse saturation logs from observation wells, have been collected over the last decades to provide insight into the sweep efficiency and flow paths of the injected water. Iterative simulations were performed to investigate different scenarios and various sensitivities with each iteration involving an update of the static model to honor both the dynamic and core/log data. While applying this iterative process it was also acknowledged that conventional core data (e.g. 1 plug per foot) may not capture the high permeability streaks in these heterogeneous reservoirs that control much of the reservoir flow behaviour, hence much denser plugging and core examination is required. In addition, permeability upscaling procedures need to take into account the fact that core plugs may not represent the effective permeability of the larger connected vuggy pore systems. The improved understanding of reservoir heterogeneity, the more robust reservoir characterization, and the improved history matching demonstrates that a better representation of reservoir dynamics is achieved. This provides a solid platform for designing and planning future EOR schemes.
- Europe (0.87)
- Asia > Middle East > UAE (0.28)
- North America > United States > Alaska (0.28)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (22 more...)
Study Geophysical Response of Middle East Carbonate Reservoir using Computational Rock Physics Approach
Zhan, Xin (ExxonMobil Upstream Research Company) | Fullmer, Shawn M. (ExxonMobil Upstream Research Company) | Lu, Chih-ping (ExxonMobil Upstream Research Company) | Harris, Christopher E. (ExxonMobil Upstream Research Company) | Martinez, Alex (ExxonMobil Upstream Research Company)
Abstract This paper provides a new computational rock physics study of middle east carbonate rock. Computed elastic and electrical properties from real rock micro-tomographis and constructed 3D sphere packs build direct link between rock microstructure and its elastic, electrical responses. Multi-resolution CT scans (resolution varying from nanometer to micron) are taken for carbonate core samples belonging to different facies from middle east carbonate reservoirs. Different carbonate petrophysical pore types shows clearly different pore structures (pore shape, size, connectivity). Laplace equation and linear Stokes equation are directly solved on those 3D rock micro-tomographis to compute electrical conductivity and hydraulic permeability using finite difference method (FD). Elastic properties (Vp, Vs, bulk modulus, shear modulus, Young's modulus and Poisson's Ratio) are computed by solving linear stress-strain relationship using finite element method (FEM). To further extend predicting capability, a family of 3D model granular porous media with different porosity, pore (grain) aspect ratio, pore (grain) size distribution, pore connectivity and spatial arrangement are built to represent different carbonate petrophysical pore types. Results for different carbonate facies (Wackestone with roundish micropore system (microporosity); Grainstone, Packstone with interpartical pore (IP) system; Rudstone with vuggy porosity and IP frame) are shown. Measurements on core plugs compare well with modeling results and computed values. We can rigorously determine the pore geometry related parameters in effective medium based model (Xu-Payne model) from numerical computation to interpret and predict log response for upscaling. Finally, AVO seismic forward modeling is built to quantify porosity, fluid saturation and lithology (facies) effect on seismic response for middle east carbonate reservoir. A complete study at pore and core scale, log scale to seismic scale is achieved. Conclusions and recommendations on inverting porosity, fluid saturation and carbonate facies from pre-stack seismic in carbonate reservoir are given at the end.
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Carbonate reservoirs (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Seismic processing and interpretation (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Core analysis (1.00)
Abstract This paper describes the work undertaken to build a 3D static model of a Lower Cretaceous Carbonate Reservoir located in Kazakhstan called X-Field. This reservoir has been pervasively dolomitized, and presents several challenges for development optimization. This model will be used to support further appraisal and development activities, in order to tackle key uncertainties, such as reservoir quality distribution. All of the available data were quality controlled, analyzed and interpreted (including data from logs and cores), to produce porosity, permeability and RRT (reservoir rock type) models. These are believed to be representative of the reservoir's behavior and connectivity. In order to identify the main flow zones and understand the reservoir's complexity, Reservoir Rock Typing (RRT) was performed on two cored wells by analyzing CCAL and SCAL data, including thin sections, MICP measurements, porosity and permeability. A comprehensive RRT methodology using Winland R35 method and poro-perm plot was followed, which resulted in defining five rock types. The outcome from the RRT study was confirmed by poro-perm plot, which showed the presence of five flow units. The 3D model was built by using corner point grids (CPG), and contains a total of 2,380,050 cells. Several models of porosity and RRT were generated, representing "low", "mid", and "high" case scenarios of reservoir quality distribution. Finally, permeability models were created for each scenario, conditioned to their respective Winland R35 porosity-permeability relationships per RRT. Comparison between the different porosity (Φ), permeability (k), and RRT models and scenarios, will allow a better management of the reservoir uncertainties during the appraisal and development stages for this reservoir.
- Geology > Geological Subdiscipline > Stratigraphy (0.46)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock (0.30)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Carbonate reservoirs (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Geologic modeling (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Core analysis (1.00)
Summary Occurrence of moldic and vuggy pores, fractures and other pore structures due to diagenesis in carbonate rocks much complicates the relationships between impedance and porosity. Acoustic impedance in carbonates is influenced by factors such as porosity, pore structure/fracture, fluid content, and lithology. Using a frame flexibility factor (?) derived from a poroelastic model to characterize pore structure in reservoir rocks, we found that its product with porosity could result in a much better correlation with sonic velocity (Vp = A-B*??) and acoustic impedance (AI = C-D*??), where A, B, C and D is 6.60, 3.14, 18.21, and 9.88 respectively for a deep low-porosity carbonate reservoir studied in this paper. These new relationships could also be useful to improve seismic inversion of ultra-deep hydrocarbon reservoirs in other similar environments.
- Asia (0.97)
- North America > United States > Texas (0.29)
- North America > United States > Mississippi > Marion County (0.25)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (22 more...)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Carbonate reservoirs (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Seismic processing and interpretation (0.96)