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Results
Abstract We present numerical results of a propagating hydraulic fracture in weak rock formations. The results were obtained from a Finite Element Hydraulic Fracturing model which simulates all the involved non-linear and coupled processes. The fracture is driven by pumping of an incompressible viscous fluid with Newtonian rheology. The fracturing fluid leak-off in the host rock formation is also considered. For propagation criterion a cohesive-softening model is implemented in interface finite elements and the bulk rock deformation is modelled by Mohr-Coulomb yield criterion. The main objective of this research work is to determine the influence of the stress-field, pore pressure field and pumping parameters on rock plastic deformation and its implications on fracturing net-pressure and fracture dimensions. It has been previously shown that in weak formations plastic yielding and the associated rock dilation create shielding of the fracture tip and hence larger pressures are needed to propagate the fractures and the created fractures are shorter and wider. We extend these studies to investigate the influence of the pore pressure which has been previously ignored. We found that high anisotropic stress field and high initial pore-pressure fields increase the plastic yielding in a rock formation demanding higher net-pressures for propagating a fracture and the created fractures are shorter and wider. This non-linear analysis and results may explain the differences observed in net-pressures between field measurements and conventional model predictions. These findings are important in improving the numerical simulators of modelling hydraulic fracturing in particular for short fractures in weak formations for sand control applications. The results are also important to better prediction of vertical fracture growth and containment in shale-natural gas stimulations where there are serious environmental concerns on the risk of ground-water contamination.
- Africa (0.46)
- Europe > Norway > Norwegian Sea (0.25)
Abstract Upscaling is often applied to generate practical simulation models from highly detailed geocellular descriptions. Upscaling of reservoir properties is critical to translate parameters measured from laboratory samples into values representative of the much larger grid blocks used in field simulators. In this paper an upscaling methodology for naturally fractured reservoir simulation is developed and the effect of dominant forces on upscaling parameters is considered. Dominant forces which affect the fluid flow in naturally fractured reservoir are capillary force, gravity force and viscosity force. According to force dominancy, three different scenarios are proposed. In each scenario synthetic fine grid model represents actual fracture distribution. And upscaling parameters of each equivalent dual medium model are determined by matching the results of the fine grid model simulation. In the first scenario viscose force is dominant. After running simulations the results of single porosity and dual permeability models are perfectly matched. So there is no need to tune the dual permeability model. In the second scenario in which capillary force is dominant, dual permeability and single porosity models showgood match. The results could be improved by tuning fracture porosity, fracture permeability and shape factor. Fracture porosity reduction and permeability reduction increases the pressure and water breakthrough time while decreases the oil production. In the third scenario in which gravity force is dominant the matching parameter is fracture porosity. Reduction of fracture porosity increases pressure and water cut while decreases oil and gas production. To investigate the accuracy of the upscaling method, following validity tests are implemented; flow rate test, well location, saturation function, viscosity ratio and block height. Comparing the results show that in this reservoir, dual permeability model matched better with the fine grid model than dual porosity model.
- Information Technology > Modeling & Simulation (0.54)
- Information Technology > Communications > Networks (0.40)
Abstract Acid treatments in high temperature deep wells drilled in carbonate reservoirs represent a challenge to the oil industry. The high temperature of deep wells requires a special formulation of emulsified acid that can be stable and effective at such high temperatures. At these high temperatures, both the reaction rate between acid and rock, and corrosion rate of tubulars are high. This fact makes protection of tubulars and reducing the reaction rate between rock and acid challenging. A new emulsifier was used to prepare emulsified acids that can be used in stimulating deep wells drilled in carbonate reservoirs. All emulsified acid systems were formulated at 0.7 acid volume fraction, and the final HCl concentration was 15 wt%. A coreflood study was conducted in order to study the efficiency of the new emulsified acid to create wormholes, and to increase the efficiency of the stimulation treatment. Both low and high permeability Indiana limestone cores were used in the present study. The effect of acid injection rate, rock permeability, and emulsifier concentration on the performance of emulsified acid systems were studied. The reaction between emulsified acid and limestone rocks was studied using a rotating disk apparatus at 230 ยบF, and rotational speeds up to 1,500 rpm. The results showed, for both low and high permeability Indiana limestone cores, the new emulsified acid system created deep wormholes at all injection rates (0.5 to 10 cm/min), with no face dissolution encountered during acid injection. The reaction rate between the new emulsified acid and limestone cores was measured using a rotating disk at 230 ยบF. The dissolution rate increased as the rotational speed increased, indicating that reaction between emulsified acid and limestone is a mass transfer limited reaction. Both reaction rate and diffusion rate decreased as the emulsifier concentration increased from 0.5 to 2.0 vol%. From these results, the new emulsifier can be used in formulating emulsified acid systems that can be used effectively in stimulation of high temperature deep wells. This paper summarizes the results of testing the new emulsified system, and recommends its use for field application in deep carbonate reservoirs.
- North America > United States > Texas (1.00)
- Asia (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Lifecycle > Disposal/Injection (0.68)
- 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)
- (24 more...)
Optimization of SAGD in Conductive Fractured Reservoir
Fattahi, A.. (Faculty of Petroleum and Renewable Energy Engineering, Universiti Teknologi Malaysia) | Zare, A. R. (Faculty of Petroleum and Renewable Energy Engineering, Universiti Teknologi Malaysia) | Akhondzadeh, H.. (Faculty of Petroleum and Renewable Energy Engineering, Universiti Teknologi Malaysia) | Derahman, M. N. (Faculty of Petroleum and Renewable Energy Engineering, Universiti Teknologi Malaysia) | Yunan, M. H. (Faculty of Petroleum and Renewable Energy Engineering, Universiti Teknologi Malaysia)
Abstract Steam Assisted Gravity Drainage is a successful process that has been applied to extract heavy oil and bitumen mostly in Canada. Conductive fractures as reservoir heterogeneity are spaced a few meters from each other and differ from network fractures. There are a few studies investigating the impact of such fractures on SAGD performance. This work is a numerical study examining the relative location and configuration of wells to conductive fractures as an attempt to optimize SAGD process in three types of conductive fractures including horizontal, vertical and oriented fractures. While vertical fractures located above the well pair enhance the oil recovery rate at early time, those located far from the well pair do not affect the process performance. Consequently, to optimize the process, the wells should be applied beneath the vertical fracture. For the vertical conductive fractures locating at bottom of the reservoir, higher well spacing results in more desirable performance if the wells are drilled at the place of the fracture. Sensitivity analysis of injector-producer well spacing illustrated that for horizontal fractures locating around 5 m from the reservoir base, the injector should be drilled above the fracture to enhance the process performance much more than the case of having the injection well below the fracture. Also it is showed that the well pair should be located in a manner that oriented fractures with positive slope place at right hand side and near the wells. Moreover, Off-setting the wells in the fracture direction resulted in enhanced behavior of the process. In low permeability tar sands, hydraulic fracturing can mimic vertical conductive fractures which improve steam chamber expansion, hence resulting in better performance. This study suggests some screening criteria for the well placement design to enhance the oil recovery in conductive fractured reservoirs.
- Asia (1.00)
- North America > Canada > Alberta (0.48)
- North America > Canada > Alberta > Western Canada Sedimentary Basin > Alberta Basin > Cold Lake Field > Clearwater Formation > 995053 2D Cold Lake 2-10-63-2 Well (0.99)
- North America > Canada > Alberta > Athabasca Field > Allied Et Al Athabasca 6-13-66-23 Well (0.99)
- Asia > Middle East > Bahrain > Awali Field (0.99)
- Asia > Middle East > Turkey > Raman Field (0.98)
Abstract Acid treatment in carbonate reservoirs targets to restore or to stimulate the near-well area. Emulsified acid can be used in matrix acidizing and acid fracturing treatments. The delayed nature of emulsified acid is useful in creating deep wormhole and etched fracture surfaces. Almost all coreflood work done before was performed on cores fully saturated with water. Therefore, the main objective of the present work is to study the effect of presence of crude oil in the formation on the performance of emulsified acid in stimulating carbonate formation. A coreflood study was conducted using high permeability Indiana limestone cores which have dimensions of 1.5" diameter and 6" long. The effect of the presence of crude oil inside the core on the volume of acid to achieve acid breakthrough was studied. Also, the size, numbers and distribution of the resulted wormholes as a function of the core fluid content was studied through the analysis of the CT images on the core after injection of emulsified acid. Also, the effect of the acid injection rate on these parameters was studied. Cores that are fully saturated with water and cores saturated with crude oil and water were used to study the performance of emulsified acids. From the coreflood study, there was no optimum injection rate for an emulsified acid system when it was tested against high permeability Indiana limestone cores fully saturated with water. For high permeability Indiana limestone cores, emulsified acid enhanced the rock permeability when the acid injected at high rates. For cores saturated with crude oil and water, there was no clear relationship between volumes of emulsified acid required to achieve breakthrough and emulsified acid injection rate. Also, volumes to emulsified acid to achieve breakthrough in cores saturated with crude oil and water are greater, compared to acid volumes required to achieve breakthrough in cores fully saturated with water. Emulsified acid system is effective in stimulating limestone cores, at different acid injection rates and at high temperatures, even the cores were saturated with water or saturated with crude oil and water.
- North America > United States > Texas (1.00)
- North America > United States > Indiana (0.67)
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Lifecycle > Disposal/Injection (0.69)
- 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)
- (24 more...)
Abstract The benefits of Hydraulic Fracturing (HF) are well recognized in the oil industry, even if in many world regions it is still seen as a remedial operation rather than a reservoir development strategy. The big part of worldwide HF operations, are performed extensively in the US and Canada, primarily for reservoir development purposes of tight gas fields. However during the last few years, the global trend has seen a change and HF is now encouraged for adding new reserves, aiding the development of low permeability marginal reservoirs and prolonging life of brown fields. In Congo Onshore, HF is now a consolidated reality, with more than 70 frac jobs pumped. Good results have encouraged management to increase fracturing activity: nowadays HF is performed on all the infill wells that are drilled in the low permeability layers of the reservoir. From the early stages of development only the layers with the higher permeability were produced, while the possibility to develop the low permeability layers was not considered, because of very poor or zero production results due to the application of conventional completion strategy. Since HF is now performed as a standard practice on new wells, it has been reconsidered for the application on old wells completed in the low permeability layers. The challenge encountered on these old wells, has been the presence of long perforated interval. Rigless operations (such as sand plug) and work-over operations (such as cementing of old perforated interval and re-perforations) have been needed for fracturing in order to avoid fracture initiation issues like multiple fractures and early screenout. This paper will show the lessons learned and the main results achieved during this campaign and it is particularly focused on operational and logistic aspects, offering a full operational overview to all Companies and Operators that intend to apply this technology on their assets, maximizing oil recovery.
- Geology > Structural Geology (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- North America > United States > California > Sacramento Basin > 3 Formation (0.99)
- Europe > Norway > North Sea > Central North Sea > Central Graben > Block 2/8 > Valhall Field > Tor Formation (0.99)
- Europe > Norway > North Sea > Central North Sea > Central Graben > Block 2/8 > Valhall Field > Hod Formation (0.99)
- (4 more...)
Promising Approaches to Enhance SAGD Performance in Uneconomical Tar-Sands
Akhondzadeh, H.. (Faculty of Petroleum and Renewable Energy Engineering Universiti Teknologi Malaysia) | Fattahi, A.. (Faculty of Petroleum and Renewable Energy Engineering Universiti Teknologi Malaysia) | Zare, A. R. (Faculty of Petroleum and Renewable Energy Engineering Universiti Teknologi Malaysia) | Derahman, M. N. (Faculty of Petroleum and Renewable Energy Engineering Universiti Teknologi Malaysia) | Idriss, A. K. (Faculty of Petroleum and Renewable Energy Engineering Universiti Teknologi Malaysia)
Abstract Low permeability, shale barriers and low thickness are the main issues making significant portion of the immense heavy oil and bitumen resource uneconomical to produce. Two main troublesome cases were investigated in this study to address by applying appropriate solutions in SAGD process; firstly reservoirs with shale barriers and low permeability and secondly thin reservoirs. In cases of low vertical permeability due to shale inclusion in the reservoirs, the effect of induced vertical fracture resulted in faster upward steam chamber expansion and increased oil recovery rate. Sensitivity analysis showed higher well spacing is beneficial to the process while applying the induced vertical fracture. In thin reservoirs, steam chamber reaches overburden faster and increases cumulative steam-oil ratio (cSOR), hence making recovery processes uneconomical. Appropriate placement of Induced Horizontal-Fractures (IHF) and off-set vertical wells with the later being in halfway of two adjacent horizontal well pairs in SAGD and acting as a steam injector was applied. The results showed such applications reduce cSOR. Found from the sensitivity analysis, Induced Horizontal-Fractures positioned in the injector and the producer place improves oil recovery in thin reservoirs. When applying the fracture just in producer location, the oil recovery result is superior to the former case. In fact, IHF provide a path facilitating the oil drainage to producer that leads to faster oil transportation. The Off-set vertical well in the thin reservoir sweeps a part of the reservoir located beyond the chamber edges of two adjacent well pairs, hence reducing recovery time and cSOR. Based on sensitivity analysis, the most promising result of the process is achieved when initiating steam injection in the vertical injector from the beginning of the process.
- Asia (0.69)
- North America > United States (0.47)
- North America > Canada > Alberta (0.29)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (1.00)
- Geology > Petroleum Play Type > Unconventional Play > Heavy Oil Play (1.00)
Abstract Water is injected in the hydrocarbon reservoir to serve two purposes, to maintain reservoir pressure and to displace oil as production proceeds in the reservoir. In recent years, smart wells coupled with reservoir simulation models are used to improve the results of water injection performance. High frequency data (pressure, flow rate, etc.) that is a product of the smart wells provide the basis for a closed-loop, fast track updating of the dynamic reservoir models. While high frequency updating of the reservoir model remains a challenge, there are emerging technologies that can make such objectives achievable. An integrated approach that combines analytical and numerical solutions with artificial intelligence and data mining is proposed to ultimately achieve the closed-loop, fast track updating system. This study is the first step in that direction. In this work the ability of analytical solutions to calculate reservoir water saturation profiles from field water cut data are investigated. Different flow regimes and reservoir geometries are considered during this study. Diffuse, segregated and capillary influenced flow models are analyzed in both one and two dimensional water injection using a commercial numerical simulator. Different analytical formulations are applied for each flow regime in order to reproduce simulation production data. For each model a specific relative permeability relation is assigned and tuned with the aim of matching water breakthrough time and water cut history. An accurate match is achieved between water saturation profiles generated by the analytical models and the results by the reservoir simulator. The influence of simple reservoir heterogeneity on the robustness of the analytical models is studied.
- North America > United States (0.68)
- Africa (0.46)
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Lifecycle > Disposal/Injection (0.56)
- North America > United States > Arkansas > Smart Field (0.99)
- Asia > Indonesia > Sumatra > Riau > Central Sumatra Basin > Rokan Block > Rokan Block > Bekasap Field > Menggala Formation (0.99)
- Asia > Indonesia > Sumatra > Riau > Central Sumatra Basin > Rokan Block > Rokan Block > Bekasap Field > Bekasap Formation (0.99)
- Asia > Indonesia > Sumatra > Riau > Central Sumatra Basin > Rokan Block > Rokan Block > Bekasap Field > Bangko Formation (0.99)
Multidisciplinary Approach for Novel Application of Formation-Pressure-While-Drilling Service in High-Temperature (160 Deg.C) Low Permeability Carbonate
Bruni, Corrado (BG Group) | Odumboni, Idowu (BG Group) | Sellami, Besma (BG Group) | Turner, Marcus (Schlumberger) | Sanguinetti, Marco (Schlumberger) | Kazmer, Jorge (Schlumberger)
Abstract The Abiod formation is the principal target in the Miskar field, offshore Tunisia. Consisting of fractured geomechanically stressed carbonate with a measured matrix permeability as low as 0.1 mD. The formation dates from Campanian to lower Maastrichtian and forms a horst structure. The formation has been under production since 1996. Obtaining formation pressure data was considered critical for determining the magnitude of depletion from production, well-to-well comparisons for vertical and lateral connectivity, forward modeling, completion decisions, and refinement of the field development plan. Historically, this has been a challenge with conventional wireline (WL) formation testers for the following reasons: Severe depletion and well deviation causing differential sticking High temperatures (150 to 195ยฐ C) at the limit of tool electronics Low permeability Fractures and breakouts that can impact seal success This was overcome with a systematic multidisciplinary approach. After review of historical formation testing data, and influence on seal success with probe vs packer elements, it was decided to apply formation-pressure-while-drilling (FPWD) technology. The key questions with FPWD in this environment are: Can we achieve a good transient profile and what is potential impact of supercharging? These questions were addressed with advanced prejob modeling, which enabled determination of an optimized pretest configuration and testing procedure to minimize potential supercharging effects. While drilling, stage-in procedures were used, and mud logging total gas data were gathered to identify areas of liberated gas. Pre-run wireline petrophysical data were gathered to characterize the Petrophysic of the reservoir and to calculate an intrinsic permeability profile. Ultrasonic borehole images and caliper data were used to determine the principal horizontal stress directions, fracture frequency, and orientation and to confirm the stratigraphyc dipping of the structure. Combined, this information allowed a focused orientation of the FPWD probe and optimal station selection avoiding fractures and breakouts. This novel approach resulted in 100% seal success, >50% improvement. Four days of rig time were saved, and the required data were obtained.
- Geophysics > Borehole Geophysics (1.00)
- Geophysics > Seismic Surveying > Borehole Seismic Surveying (0.66)
- Africa > Middle East > Tunisia > Mediterranean Sea > Gabes Basin > Miskar Field (0.99)
- Africa > Middle East > Tunisia > Kairouan Governorate > Pelagian Basin > Sidi El Kilani Concession (SLK) Permit > Abiod Formation (0.99)
- Well Drilling > Drilling Measurement, Data Acquisition and Automation (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 (1.00)
Application of New Techniques for Characterization of an Eocene Carbonate Reservoir in the Gulf of Suez, Egypt
Van Steene, Marie (Schlumberger) | Vallega, Valentina (Schlumberger) | Shaaban, Sahar (Schlumberger) | Ghadiry, Sherif (Schlumberger) | Haddad, Elie (Schlumberger) | Bassim, Essam (Arabian Oil Company-PetroSalam)
Abstract A variety of recently developed techniques are available to improve carbonate rock characterization. This paper reviews the application of these techniques on an Eocene carbonate reservoir from the Gulf of Suez. Spectroscopy data was a main driver of the formation evaluation. It allowed an accurate determination of clay, pyrite and siderite with a good match to core data, while the photoelectric factor could not be used because of high barite content in the mud. Magnesium from spectroscopy indicated small amounts of dolomite were present. Since rock texture has a strong impact on porosity and permeability in carbonates, texture-sensitive tools must be included in the evaluation. Based on nuclear magnetic resonance (NMR) data, porosity partitioning analysis showed that the porosity is dominated by micro and meso pore sizes. While the default correlations used for NMR in carbonates considerably overestimate permeability, a modified SDR equation was applied to predict permeability more accurately, providing a good match to core data. Hydrocarbon properties have been found to vary vertically. NMR fluid identification stations were used to characterize the variation, which was validated by the drillstem test (DST) results. Tar was identified based on the comparison of total porosity and NMR porosity. This is an important parameter as tar can affect the reservoir producibility. Fracture analysis was performed on a data set of microresistivity image and sonic Stoneley data. The analysis performed on the Oil-Base MicroImager (OBMI) identified the orientation of the fracture system. The Stoneley wave processing determined that the majority of the fractures encountered in the reservoir were healed. This conclusion was supported by the core analysis results. The work presented in this paper demonstrates how integrating the measurements from various tools and sources provides a good understanding of reservoir producibility in carbonates. The integrated evaluation was validated with core and well test results.
- Asia > Middle East > Saudi Arabia (1.00)
- Africa > Middle East > Egypt > Suez Governorate > Suez (0.40)
- Research Report > New Finding (0.66)
- Overview > Innovation (0.50)
- Geology > Structural Geology (1.00)
- Geology > Mineral (1.00)
- Geology > Geological Subdiscipline (1.00)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock > Dolomite (0.34)
- Geophysics > Borehole Geophysics (1.00)
- Geophysics > Seismic Surveying > Borehole Seismic Surveying (0.86)
- Africa > Middle East > Egypt > South Sinai Governorate > Lagia Field > Thebes Formation (0.94)
- Africa > Middle East > Egypt > South Sinai Governorate > Lagia Field > Nukhul Formation (0.94)
- North America > United States > Gulf of Mexico > Central GOM > West Gulf Coast Tertiary Basin > Garden Banks > Block 200 > Northwestern Field (0.89)