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Results
Abstract Determining optimum location of wells is a crucial step in field development. A realistic geological model is an important factor in finding an accurate optimum well location. Usually history matching is used to come up with a realistic geological model. However, there is no unique solution to the history matching problem. Often several geological models could match the history data. This introduces some risk associated with the results of well placement optimization algorithm. In this work, we present a new modified genetic algorithm (GA) for well-placement optimization under geological uncertainty. The inputs of the algorithm are possible geological models, and the level of risk that the user can accept. In the algorithm, the classic GA is modified so that: 1) in evaluating the fitness value (cumulative production or net present value) of each individual (well location) all the possible geological models provided by users are evaluated, 2) upon convergence of the algorithm, the output is one optimum well location as the fittest individual taking into account all the provided geological models, and 3) this optimum well location is selected based on the input user-defined level of risk. Most current available algorithms in the literature do not allow the user to input the risk factor desired and individual weights for each realization. The risk-constrained algorithm will provide different optimum well locations depending on the level of risk the user wants to take. All these features make the new algorithm much more efficient and applied than current well-placement algorithms in the literature for handling geological uncertainty. We present the application of the risk-constrained algorithm to a horizontal well-placement optimization in a gas condensate reservoir, Qatar’s North Field, with multiple possible permeability fields and with different user-defined risk factors.
- Europe (1.00)
- North America (0.94)
- Asia > Middle East > Qatar > Arabian Gulf (0.36)
- Asia > Middle East > Qatar > Khuff Formation (0.99)
- Asia > Middle East > Qatar > Arabian Gulf > Rub' al Khali Basin > North Field > Laffan Formation (0.99)
Integrated Geo-Statistical Modeling – An Effective Tool to Meet the Exploration Challenge of Low Porosity Carbonate Reservoir within Najmah-Sargelu Formation, Kuwait
Nath, Prabir Kumar (Exploration Group, Kuwait Oil Company (K.S.C)) | Prasad, Raghav (Exploration Group, Kuwait Oil Company (K.S.C)) | Khan, Badruzzaman (Exploration Group, Kuwait Oil Company (K.S.C)) | Singh, Sunil Kumar (Exploration Group, Kuwait Oil Company (K.S.C)) | Abu-Taleb, Reyad (Exploration Group, Kuwait Oil Company (K.S.C)) | Bader, Sara (Exploration Group, Kuwait Oil Company (K.S.C))
Abstract The emergence of low porosity carbonate lithofacies of Najmah-Sargelu Formation as a commercial hydrocarbon play has led to change the exploration perspective of these formations. Several wells from different structures in Kuwait has shown the production potential of light oil@ 1000–4000 BOPD and natural gas 3.8–19.0 MMSCFD. The production has been obtained from bituminous mudstone, wackestone and algal limestone from Najmah-Sargelu Formation. Understanding the geometry and distribution of carbonate lithofacies of Najmah-Sargelu Formation is a major exploration challenge. Geo-statistical 3D model is a dynamic tool, which has been utilized to quantify the geometry and spatial distribution of carbonate lithofacies vis-a-vis its continuity. A careful geo-statistical workflow was evolved to address the major challenges of these reservoirs. An artificial intelligence, neural network was trained against cored section and subsequently applied in the noncored sections for lithofacies prediction. Sequence Stratigraphic framework, seismic grid and 3D geo-statistical modeling were integrated to create a geological model. Core-measured rock property data were analyzed to illustrate the distributions of core porosity and permeability of Najmah-Sargelu lithofacies. The distribution of internal properties and heterogeneity has been quantitatively described as the relationship of a reservoir facies within a sequence stratigraphic framework. Spatial estimation of lithofacies and reservoir properties provides insight into the deposition and diagenetic process of the reservoir units. The depositional pattern and connectivity analysis suggests a ramp setting in inner shelf environment of deposition with three major alternate transgressive and regressive sequences. An integrated geo-statistical modeling has resulted in depicting the internal geometry and connectivity of low porosity carbonate lithofacies thereby reducing the uncertainty in volumetric assessment in the delineation phase of Najmah-Sargelu Formation.
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock (0.58)
Abstract Sequestration of carbon dioxide in a saline aquifer into shallow marine formation of Jurassic sandstones in Svalbard has been studied on unfractured cores and by using a simplified set of geological boundary conditions. In this paper, the feasibility of storing CO2 in a fracture and matrix system in a low permeable formation is studied by performing a series of laboratory experiments under different stress conditions. Laboratory core flooding experiments were conducted on two alternative fractured and unfractured cores. Water and nitrogen were injected into brine saturated cores at the reservoir conditions. The result shows that core plugs are very tight and the liquid permeability even for fractured core is less than 1 millidarcy. Under increased acting stress from 10 to 180 bar, the effective permeability of fractured core is reduced by 73 percent and fluid flow occurs through both fracture and matrix. A conceptual, generic and simple 3D numerical model using commercial reservoir simulation software and available petrophysical data was used to study the CO2 injection through fracture at different overburden pressure. The effect of different overburden pressures were applied by using respective permeabilities in simulation model. Mean pressure along the cores was used to match simulation predictions with experiments results. The result shows that even though the system is water-wet, and matrix has a very high capillary pressure, CO2 flows through both fracture and matrix. The amount of CO2 that flows through the fracture is high and is reduced by increasing overburden pressure. The quantity of dissolved CO2 in brine phase reduces by decreasing overburden pressure and increasing permeability. The faster the CO2 is flowing through the fracture less time is available for CO2 to trap as residual phase and dissolve in brine. In dipping fractured saline aquifer, CO2 plume movement in updip direction is accelerated by decreased overburden pressure and increased permeability.
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.62)
The Use of Seismic Attributes for Depth Conversion and Property Distributions, E-M Field, Offshore South Africa
Corbett, C.. (Schlumberger) | Frewin, J.. (PetroSA) | Kgogo, T.. (PetroSA) | Dubost, F.. (Schlumberger) | Navarro, R.. (Schlumberger) | Tyler, E.. (Schlumberger) | Portet, M.. (Schlumberger)
Abstract The E-M field is a gas reservoir that has been under production for nearly a decade. This paper presents the effort of the team to revise and improve the sub-surface model to delineate new drilling targets. Closure of the field to the east was uncertain, but critical to the field development plan. Inversion of the seismic data created an absolute acoustic impedance cube and a derived effective porosity cube. Attributes were extracted from each of the various seismic data, using direct and interval extractions following the interpreted surfaces. Careful inspection of the seismic amplitude in cross section revealed a flat spot, indicating a potential fluid contact. This feature was confirmed in several of the extracted attributes which were then used to constrain an iterative depth conversion. Fault interpretations in time were then adjusted to match the new depth horizons creating enechelon faults in a fashion analogous to surface outcrops observed in the Cape Town region. Uncertainty also exists with respect to the vertical isolation of the reservoirs. Log responses record a thin shale, below seismic vertical resolution, in all of the drilled wells. However, the areal extent of the shale is unknown, and vertical communication is a possibility. Stochastic representations of the potential shale extents were introduced into the dynamic fluid-flow simulation, and fed through an experimental design to test the impact on vertical connectivity. Using a proxy model from these results a Monte-Carlo simulation provided a probability distribution for the production response. The methods presented here are applicable to fields wherever sharp acoustic impedance contrasts exist between fluid types, particularly in gas reservoirs or reservoirs with an existing gas cap. Seismic attributes have refined the depth conversion for the E-M field, and the resulting geomodel provides new drilling targets for the operator.
- Geology > Structural Geology > Fault (0.95)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.68)
- Geophysics > Seismic Surveying > Seismic Processing (1.00)
- Geophysics > Seismic Surveying > Seismic Modeling > Velocity Modeling (1.00)
- Geophysics > Seismic Surveying > Seismic Interpretation (1.00)
Abstract It is well known that heterogeneity is one of the most important factors in affecting production performance. These include oil production rate, oil recovery before water breakthrough, water cut, etc. However, it has long time been a challenge to correlate the heterogeneity and the oil production performance quantitatively, especially in low permeability reservoirs. To this end, fractal dimension inferred from mercury-intrusion capillary pressure data and other parameters were used to quantitatively characterize the heterogeneity of rock in this study. Over 100 core plugs were sampled from different wells in a low permeability oil reservoir. Routine and special core analysis tests were conducted in these core samples with a permeability ranging from less than 0.1 to over 100 md. Correlation between heterogeneity and oil production performance was investigated at both the microscopic (core) and macroscopic (well and reservoir) scales. The results demonstrated that the fractal dimension was correlated with the production performance at microscopic and macroscopic levels. The oil production rate and the water breakthrough time show an inverse relationship with fractal dimension, while the water cut shows a direct relationship with fractal dimension.
- Europe > Norway > North Sea > Central North Sea > Central Graben > PL 018 > Block 2/4 > Greater Ekofisk Field > Ekofisk Field > Tor Formation (0.99)
- Europe > Norway > North Sea > Central North Sea > Central Graben > PL 018 > Block 2/4 > Greater Ekofisk Field > Ekofisk Field > Ekofisk Formation (0.99)
- Asia > China > Xinjiang Uyghur Autonomous Region > Tarim Basin > Dabei Field (0.99)
- (4 more...)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring (1.00)
Abstract To improve oil recovery from pervasively fractured reservoirs, gas injection can be considered. In such reservoirs, the fractures typically provide the flowpaths but contain a limited amount of the oil whereas the matrix often has orders of magnitude lower permeabilities but contains the oil. To improve oil recovery from such reservoirs, gas/oil gravity drainage can be applied. In this process, a gravity stable displacement can be achieved. If gas is injected which is not in equilibrium with the oil, the non-equilibrium gas components diffuse from the fracture system into the matrix and the components of the oil diffuse towards the fracture system. This results in a modification of the properties of the oil affected by diffusion and gravity drainage rates accordingly. The effects of non-equilibrium gas injection into a pervasively fractured reservoir were studied at the example of an Austrian reservoir. This type of gas injection results in a zone of decreased oil viscosity for gases such as CO2 and CH4 at the interface of the gas and the oil in the matrix. This zone of lower oil viscosity increases the gas/oil gravity drainage rates. The results show that the effect of diffusion can increase cumulative oil production up to 25 % compared with a case neglecting the effect of diffusion. The effect of diffusion could be determined for various parameters such as permeability, porosity, fracture spacing and matrix block height. While for some of the parameters, the effect of diffusion scales with the square root of time (e.g. permeability), for others an exponential relationship has been determined (fracture spacing). The results derived for the example reservoir can be used more generally to screen whether the effect of diffusion should be incorporated into reservoir studies concerning non-equilibrium gas injection and how large the error could be in case that diffusion is neglected.
- Europe (1.00)
- Asia > Middle East (1.00)
- North America > United States > Texas (0.47)
- Research Report > New Finding (0.34)
- Research Report > Experimental Study (0.34)
- Asia > Middle East > Turkey > Bati Raman Field (0.99)
- Asia > Middle East > Oman > Ad Dhahirah Governorate > Fahud Salt Basin > Natih Field (0.99)
- Asia > Middle East > Oman > Ad Dhahirah Governorate > Fahud Salt Basin > Fahud Field (0.99)
- Asia > Middle East > Iran > Khuzestan > Zagros Basin > Haft Kel Field (0.99)
Kadanwari Field: A Tight Gas Reservoir Study and a Successful Pilot Well Give New Life to an Exploited Field
Valzania, S.. (eni E&P) | Kfoury, M.. (eni E&P) | Grandis, M.. (eni E&P) | Valdisturlo, A.. (eni E&P) | Fanello, G.. (eni E&P) | Guerra, L.. (eni E&P) | Heikal, S.. (eni Pakistan) | Kashif, A.. (eni Pakistan) | Sultan, A.. (eni Pakistan)
Abstract Kadanwari field in Middle Indus Basin (Pakistan) was discovered in 1989 and brought on stream in 1995. The producing reservoirs are Cretaceous Lower Goru sands D-E-F-G. The gas production started from better quality E and F sands; after 2004 layer G started to drain western block of the field, with the first hydraulic fracture job made in Pakistan (well A). Layer G represents a complex target for petrophysical characterization; reservoir sandstones are micro-porosity rich, with variable presence of Chlorite affecting flow properties. Positive results encouraged the operator to drill & frac well B and to consider possibility to extend gas production throughout western block, including sand reservoirs of variable quality, from moderate to tight. The paper describes how reservoir study faced layer G complexity and how production data of wells A and B allowed a post frac-job evaluation integrating well-test data and frac-job interpretations into 3D dynamic model. After history match, the computed GOIP suggested an infilling program in G sand reservoir, with side-tracks of existing wells and new wells, all hydraulically fractured. So far, one sidetrack and one new well have been drilled; results fully confirmed the complexity of local geological setting. The sidetrack revealed rock quality slightly better than expected (frac not necessary). Pilot well C targeted G-Sand in a sweet seismic anomaly in western area, a gas flare was observed during DST pre-frac. Mini-Fall Off was conducted to estimate closure pressure and effective mobility, but permeability computed from MFO was not conclusive due to important filtrate invasion. DST post hydraulic fracture job confirmed commercial gas rate production higher than 1 MMscfd with a peak of 3.5 MMscfd. The successful pilot well results open new horizon to improve reserve from tight sand of Lower Goru formation.
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (1.00)
- Geology > Geological Subdiscipline (1.00)
- Asia > Pakistan > Sindh > Lower Indus Basin > Goru Formation (0.99)
- Asia > Pakistan > Sindh > Khairpur District > Indus Basin > Kadanwari Field (0.99)
Abstract The production properties of chalk from the Tor and Ekofisk Formations of a Danish North Sea oil reservoir were compared in two core flooding experiments at the conditions of the reservoir. Both experiments started with a water-flooding, and then continued with a CO2-flooding. The Tor core sample was saturated with live oil to So=85.0 %, while the Ekofisk sample was saturated to So=63.7 %, the difference reflecting a difference in capillary pressure. The remainder of the pore space contained formation water. The water-flooding resulted in Sorw=25.3 % for the Tor chalk, and Sorw=37.7 % for the Ekofisk chalk. The difference in Sorw reflects different production properties during water-flooding of the Tor chalk and the Ekofisk chalk. After changing the flooding agent to CO2, the oil production resumed in both experiments, and resulted in SorCO2=5.8 % for the Tor chalk and SorCO2=4.6 % for the Ekofisk chalk. The Tor chalk produced 70.2 %OOIP during the water-flooding and 23.0 %OOIP during the CO2-flooding. In contrast, the Ekofisk chalk produced 40.8 % OOIP during the water-flooding and 52.1 % OOIP during the CO2-flooding. The inferior production properties during water-flooding for the Ekofisk chalk did not result in similar poor production properties during the CO2-flooding. The Tor chalk and the Ekofisk chalk showed production profiles that were very similar in the later part of the CO2-flooding, but differed in the early part, where the Tor chalk produced water, while the Ekofisk chalk produced oil. It is concluded that the Tor chalk and the Ekofisk chalk had different production properties in the water-flooding, but similar production properties in the CO2-flooding. Because the water-flooding left much more oil in the Ekofisk chalk, the CO2-flooding could recover a much larger oil volume from this rock. Neither the Tor sample nor the Ekofisk sample showed evidence of dissolution after the experiments. Both samples remained within the elastic regime all through the experiments. A significant potential for CO2 EOR may be present in Ekofisk chalk that is non-economic for water-flooding.
- Europe > Denmark > North Sea > Danish Sector > Central Graben > Block 5604/29 > South Arne Field (0.99)
- Europe > Denmark > North Sea > Danish Sector > Central Graben > Block 5505/13 > Halfdan Field > Maastrichtian Formation (0.99)
- Europe > Denmark > North Sea > Danish Sector > Central Graben > Block 5505/13 > Halfdan Field > Danian Formation (0.99)
- (13 more...)
Abstract During under-balanced drilling (UBD) of a horizontal well, down-hole pressure and temperature, as well as surface rate and pressure data are acquired. Theoretically, estimation of reservoir permeability profile can be achieved by quantitative analysis of these data. However, in practice, not only is a fine-grid reservoir simulator required to simulate the drilling schedule change due to tripping, completions, workovers, increase of well length with drilling and fluid flow in reservoir, but also an effective inversion approach is needed to estimate the reservoir parameters. The problem of reservoir characterization using UBD data has been studied by several previous workers. At current state of the art, neither analytical models nor commercial reservoir simulators are completely suitable for modeling the coupled system of UBD and reservoir fluid flow. In this paper, we focus on the development of an automatic history matching technique to interpret the measured oil rate and down-hole pressure data while drilling. Our contributions are three fold. Firstly, a two-phase 3D reservoir simulator was developed in which the UBD drilling process was coupled into the reservoir simulator. Next, the reservoir simulator is applied to simulate the entire drilling process from penetrating the pay-zone until the well is complete. Secondly, a least square method is applied to match the down-hole pressure and oil rate data. The inversion for a synthetic UBD data set and realistic UBD data are demonstrated on a multi-zoned reservoir model. The results show that permeability and initial reservoir pressure can be obtained by matching down-hole pressure or oil rate in a short time of exposure to the reservoir section. Finally, we offer the details for implementing the UBD process in the simulator and discuss the practical issues of the application of UBD data in reservoir characterization through this automatic history matching technique.
- North America > United States (1.00)
- Europe (1.00)
Abstract The Tesnus sandstone was deposited during the late-Mississippian/early-Pennsylvanian time in clastic debris flows. In general, it consists of a series of sand/mudstone turbidite sequences that are deposited in thicknesses varying from a few hundred to several thousand feet overall. The uppermost Tesnus consists of amalgamated and thinly-bedded sands that contain poor–good vertical connectivity and tend to have better ultimate recoveries. The lower sands are layered sands consisting of thin interbedded sandstone and shale sequences with poor vertical connectivity. These sands present an analysis problem for conventional open-hole logs, as standard porosity interpretation is not directly related to well performance as a result of the high clay content and poor permeability. Hydrocarbon production from the Tesnus is primarily natural gas with a varying amount of CO2 content, ranging from 1—30%, and very minor amounts of formation water. Sand and shale sequences can be as thin as 1–2 in. These thin zones could have high permeability zones next to zones of no permeability. Thin bed logging approaches were used, but could not adequately measure the volume nor evaluate the quality of the reservoir. Magnetic Resonance logs were added to the typical logging program in an attempt to gain a better understanding of this complexity. The Bray-Smith bin permeability equation was used with the T2 (relaxation) response to accurately define permeability. The presence of hydrocarbon was clearly indicated by the T1 (polarization) response. These answers allowed completions to be targeted in the more productive parts of the Tesnus and enhanced the calculation of net pay. This paper summarizes the results of using these measurements to design completions in this difficult reservoir. This approach can be applied in many difficult evaluation situations.
- 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)
- (21 more...)