bluuebunny/crossref_metadata_2025_split huggingface dataset:
Fracture Network Parameters in Dynamic Models of Fractured Reservoir and Its Upscaling
Authors: Sohooli Kh.. 
Published: February 2012

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.
Deepwater Drilling in Both Hard and Abrasive Formations: The Continuing Challenge of Bit Optimization
Authors: Murphy Dominic , Mackay Donald , Gilmour James , Tetley Nicholas , Centala Prabhakaran , Iwere Edward , Bits Smith 
Published: February 2012

AbstractDiscovery of the Jubilee field, offshore West Africa presented a new challenge to the drilling industry when it had to contend with hard sandstone drilling in a deepwater environment. A solution to the key 12¼" section was developed utilizing a 4D modeling system, which accelerated optimization in the large hole section. This resulted in one bottom hole assembly (BHA) run to total depth (TD), compared with an average of four BHA runs previously. Additional modeling achieved a doubling of rate of penetration (ROP).Further improvement to the one-run success would involve risk, and engineers had to weigh the prospective gain against the potential loss. In deepwater, particularly with a successful solution in place, high operating costs generally reduce the motivation to embrace change even if a potential cost-reducing solution could produce a significant economic impact. Achieving additional gains required an engineered approach to reduce the risks of deploying new solutions.During the initial campaign the simulation models were constructed around standard rock types. However, the acquisition of reservoir core allowed direct testing on actual formation. This valuable new information became the basis for a new 12¼" PDC bit design and provided the justification for field testing. Additionally, different well plans called for a more challenging 17½" hole section on a new development. To solve the challenge, the operator considered using a different bit type and/or smaller hole size. Based on simulation results, and an analysis of global offset data of both sizes, the smaller hole size option was selected.The initiatives have been extremely successful, culminating in two wells drilled in record time, with one of them reducing drilling time by 40%. This work has demonstrated that continuous improvement is possible, but where the cost of failure is high, a thorough engineering analysis is required to justify each change.
Promising Approaches to Enhance SAGD Performance in Uneconomical Tar-Sands
Authors: Akhondzadeh H.. , Fattahi A.. , Zare A. R. , Derahman M. N. , Idriss A. K. 
Published: February 2012

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.
Shale Gas Feasibility in Lacustrine Basin, Neem - Azraq Area, Muglad Basin, SUDAN
Authors: Ibrahim Maimona Mohamed 
Published: February 2012

Abstract
Is shale gas feasible in lacustrine basins?
Shale gas has become an increasingly more important source of natural gas in the United States over the past decades. Less attention given to shale gas in lacustrine basins and the few cases are not encouraging.
Abu Gabra formation act as the main effective source rock and reservoir in the same time gross thickness reach to about 7000m at the depocenter and characterized by the interbedded sands which producing condensate, light oil and recently considerable volumes of associated and dry gas.
Geochemical evaluation carried to evaluate the source rock, pyrolysis analysis results of 617 geochemical rock samples from Azraq wells and 337 geochemical rock samples from Neem wells, used to evaluate the richness of source rock (TOC), kerogen type (HI, S2) and thermal maturity (Tmax). VRo readings of 119 rock samples from Azraq wells and 73 geochemical rock samples from Neem wells used to measure the thermal maturity. 1D modeling done to predict the geothermal history and heat flow of the study area. The geomechanical characteristics of the source rock (brittleness) evaluated using the mineral and metal analysis result of 3 core samples from selected wells.
Based on the main key parameters used to evaluate shale gas in Marine basins there is high feasibility of shale gas in Lacustrine basin, where the average TOC in the study area (2.0 wt% - 3.0 wt%), VRo (0.48 C"" 1.0 to penetrated intervals) high heat flow (peak in tertiary 83 mw/m2).
High challenge of; litho-facies variation within short distance (difficulty of detecting sweet spot), suppression of thermal maturity, technological challenge of fracturing tools stands there to answer whether it will be success and economical viable?..
Orbital Forcing and Milankovitch Cyclicity Constraint During Permian Deposition on the Northern Margin of Africa, Southern Tunisia
Authors: Soua Mohamed 
Published: February 2012

Abstract
Rhythmic bedding forms one of the most characteristic features of the Late Permian in southern Tunisia. For almost a century, these bedding cycles have been interpreted to be only a part of reefal complex structure. These bedding cycles have been also identified in several neighboring wells, as well as in Libyan Jeffara, with different depositional environmental settings, interpreted as a climate variations controlled by cyclic variations in the Earth's orbit. A great variety of bedding cycles, from centimeter to meter-scale, have been described in outcrops and cores. However, exploration geophysical well logs are rarely used for this purpose, although these allow the study of thick successions of Middle-Late (either to early) Permian at decimeter-scale resolution and are widely available in the Jeffara Basin (Southern Tunisia). Therefore, a frequency analysis has been carried out of the Permian interval in well logs of four (04) available boreholes from the Jeffara basin sector. The interval contains cyclic intervals in most of the areas that underwent gradual subsidence during deposition of the Permian. In contrast, predominantly chaotic log responses are encountered in the Southwestern of the basin (northern limit of the Bou Nemcha-Telemzane complex high, BTC). Based on the calculated frequency spectra, a selection of logs showing pronounced cyclicity was made possible and used in order to identify the astronomical periodicity type represented in the sediments (i.e. eccentricity, obliquity or precession cycles). Alternatively, the Permian interval contains cycles which could be interpreted to represent 100 ky eccentricity and 40 ky obliquity Milankovitch cycles. A gradual decrease of cycle wavelength can be traced along the Roadian–Dzhulfian (and either Changhsingian) interval of several wells that probably reflects a regional decrease in primary carbonate production during this period. In this study the Permian system, in Tunisia, is revised for the first time as it is assigned to the international system nomenclature (standard chronostratigraphy). Using time series analysis, sedimentation rate and duration intervals have been also calculated.
Determination of Saturation Distributions in Water Displacement by Analytical Models
Authors: Haghighat S. Alireza , Mohaghegh Shahab D. 
Published: February 2012

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.
Application of Surrogate Reservoir Model (SRM) to an Onshore Green Field in Saudi Arabia; Case Study
Authors: Mohaghegh Shahab D. , Liu Jim , Gaskari Razi , Maysami Mohammad , Olukoko Olugbenga A. 
Published: February 2012

Abstract
Application of the Surrogate Reservoir Model (SRM) to an onshore green field in Saudi Arabia is the subject of this paper. SRM is a recently introduced technology that is used to tap into the unrealized potential of the reservoir simulation models. High computational cost and long processing time of reservoir simulation models limit our ability to perform comprehensive sensitivity analysis, quantify uncertainties and risks associated with the geologic and operational parameters or to evaluate a large set of scenarios for development of green fields. SRM accurately replicates the results of a numerical simulation model with very low computational cost and low turnaround period and allows for extended study of reservoir behavior and potentials. SRM represents the application of artificial intelligence and data mining to reservoir simulation and modeling.
In this paper, development and the results of the SRM for an onshore green field in Saudi Arabia is presented. A reservoir simulation model has been developed for this green field using Saudi Aramco's in-house POWERS™ simulator. The geological model that serves as the foundation of the simulation model is developed using an analogy that incorporates limited measured data augmented with information from similar fields producing from the same formations. The reservoir simulation model consists of 1.4 million active grid blocks, including 40 vertical production wells and 22 vertical water injection wells.
Steps involved in developing the SRM are identifying the number of runs that are required for the development of the SRM, making the runs, extracting static and dynamic data from the simulation runs to develop the necessary spatio-temporal dataset, identifying the key performance indicators (KPIs) that rank the influence of different reservoir characteristics on the oil and gas production in the field, training and matching the results of the simulation model, and finally validating the performance of the SRM using a blind simulation run.
SRM for this reservoir is then used to perform sensitivity analysis as well as quantification of uncertainties associated with the geological model. These analyses that require thousands of simulation runs were performed using the SRM in minutes.
Performance Enhancements in Metal-Crosslinked Fracturing Fluid
Authors: Kalgaonkar Rajendra , Patil Prajakta 
Published: February 2012

Abstract
Hydraulic fracturing employs crosslinked polymeric gels that are pumped into a subterranean formation with sufficient viscosity properties to generate fracture geometry in the subterranean rock and transport solid proppants to hold the fracture open. The extent of crosslinking a polymeric gel can significantly contribute to success or failure of a fracturing treatment. Crosslinking agents used in commercial fracturing applications include borate, titanium, and zirconium (Zr) complex ions.
As fracturing fluid is pumped downhole, it experiences different shears, such as high shear caused by tubulars and low shear in the fracture. Typically, polymeric gels are shear-thinning and will reduce in viscosity on application of high shear. The fracturing fluid's inability to shear-recover as it transitions from a high-shear regime in tubulars to a low-shear regime as it enters the fracture will lead to compromising of near-wellbore (NWB) proppant transport, and treatment can screenout. Borate crosslinkers that are known to provide the shear-recovery property to the fracturing gel typically have a temperature limitation of 300°F. Conversely, metal crosslinkers that have good temperature stability beyond 300°F are prone to irreversible shear degradation as the fluid passes from the high-shear to a low-shear regime, thus compromising efficient proppant transportation inside the fracture.
This paper presents the development of a novel shear-stable fracturing fluid for high-temperature applications. Rheological characterization was performed with a Fann Model 50-type viscometer at temperatures greater than 300°F using typical wellbore shear rates including shear-history profiles. The fluid chemistry of a Zr crosslinker and buffer combination that controls the crosslinker kinetics to yield shear-resilient and shear-recoverable viscoelastic gel after passing through the shear-history profile is presented. Additionally presented are regained permeability results obtained using conventional breakers that demonstrated the frac fluid's cleanup property.
Including the Effect of Capillary Pressure to Estimate Critical Rate in Water Coning Well
Authors: Ling Kegang , Shen Zheng 
Published: February 2012

Abstract
For oil reservoir with bottom water and/or gas cap, gas and water conings impose serious problems during the oil production. Coning leads to the premature gas and water breakthrough thus results in high water cut and gas oil ratio, which require a higher surface facility capacity to process excessively produced water and larger three-phase separators to separate gas, oil, and water. Consequences of early breakthrough are large footprint due to large facility, more energy to operate field, and low oil recovery. Even though numerous studies had been focused on solving the critical oil rate for gas and water coning problems, to our knowledge none of them considers the effect of capillary pressure on critical oil rate. The ignorance of capillary pressure caused the error of calculated critical rate to rise to 300%, according to the real field case study.
The errors caused by neglecting capillary pressure are severe in low permeability reservoirs. For the purpose of good production design, we investigated the effect of capillary pressure on critical rate estimation. Our study showed that the calculated critical rates are close to real field critical rates. The existing methods underestimate the critical rate by not taking capillary pressure into account. Therefore, more accurate critical rates can be obtained using our method. With more accurate result more reliable production plan can be designed to maximize the ultimate recovery.
The Key of Success to Manage Shallow Heavy Oil and Unconsolidated Sand Reservoir
Authors: Rizkallah M.. , Kamal S.. , Hassan W.. , Mamdouh M.. , Taha A.. , Khaled M.. , Hassan I.. , Waly H.. , Tag A.. 
Published: February 2012

Abstract
Heavy oil is an unconventional oil resource that is characterized by high viscosities and high densities compared to conventional oil. Most heavy oil reservoirs are deposit in shallow depths.
Issaran oil field is located 290 KM southeast of Cairo and 3KM inland from the western shore of the Gulf of Suez covering 20,000 acres. The field was discovered on 1981. The Zeit Sand formation in Issaran is highly unconsolidated sandstone. The oil is 10-12 API. The top of reservoir depth is around 700-800 ft, the thickness is around 15 ft. The initial reservoir pressure and temperature are 250 psi and 90°F respectively. The oil viscosity is more than 4000 cp at standard conditions and the reservoir rock is oil wet with 5-10% H2S content. The highly unconsolidated nature of the sand and the thin pay (heat losses) makes the economical production of Zeit Sand very challenging.
The OOIP in the developed area is estimates at around 2.5 MMSTB with estimated 35 % recovery factor using steam injection. The productivity of the wells initially before steaming is very low and the average cold production per well was below 5-10 BOPD.
In 2009 Scimitar initiated a reservoir simulation to study the optimum development scenario in term of wells spacing and injection/production scheme. The model assumed there is no aquifer existing (as per G&G interpretation). As of Dec. 2009, it was decided to develop the area based on 150 mt spacing (18 new wells were drilled and 9 old wells have been re-completed in Zeit sand.
This project faced a lot of challenge to produce Zeit sand formation either by cyclic steam stimulation or by steam flooding injection in the gas cap or oil leg wells, this paper will illustrate the different phases of this project and the challenges that were faced to complete the wells and handle the unconsolidated sand problem. Every effort was made to keep the cumulative voidage replacement ratio around one and the ultimate steam oil ratio below five which will have adequate reflect on the economics of the projects.
Diminishing the Gap between Mathematics and at Present Reservoir Simulators towards A Next Generation Simulator: A Strategic Approach
Authors: Jha Ashutosh Kumar , Bansal Gopal , Sangwai Jitendra 
Published: February 2012

Abstract
In a present scenario the applications of numerical reservoir simulators are very wide and extensive. Simulation is the only tool to describe quantitatively multi-phase flow in a heterogeneous reservoir. But, nowadays most of the users of reservoir simulators are becoming the hostages of computer-generated results, even though, many incorrect analysis techniques, mathematical models and computational approaches are used extensively in reservoir simulation study. This paper reveals such incorrect but commonly accepted approaches and presents alternate and correct mathematical approaches for the advancement of new generation reservoir simulators.
Firstly, wide literature survey is done and presented to show the mathematical approaches that are applied presently to the simulators. Then various examples (e.g. fracture and shale flow solutions where fine mesh discretization technique may lead to erroneous results due to singular velocities at the fracture and shale tips, fracture flow modeling using discrete point source which is replaced by continuous line source, etc.) of incorrect models are shown and proved to be the source of erroneous results and numerical instability.
After revealing such incorrect models, the solutions for eliminating this incorrect techniques and models are presented and proved numerically and analytically. Mathematical techniques and formulations used in this paper are advanced conformal mapping, streamfunction and streamline tracing, modern singular integral equation approaches, moving boundary value problems technique, artificial viscosity analysis, generalization of coordinate system, curvilinear grid generation, integral transformations, etc. which stabilize the mentioned simulation models.
In recent years the technological innovations in drilling and production and complicated reservoir studies have challenged the existing simulators so is the key target of this paper is to move in direction of the next generation simulators that can solve the various mentioned inaccuracies. Various accurate mesh generation algorithms are developed in this paper to revolutionize the modern petroleum engineering.