bluuebunny/crossref_metadata_2025_split huggingface dataset:
Smart Integrated Chemical EOR Simulation
Authors: Fadili Ali , Kristensen Morten Rode , Moreno Jaime 
Published: March 2015

Abstract
Chemical Enhanced Oil Recovery (EOR) techniques have recently seen a new revival owing to high oil consumption and favorable conditions that drove the oil price in a range where use of chemical is becoming economically viable. Advancements in technologies and understanding of past failures also contribute to this revival. However it appears that there is a lack of a comprehensive tool which allows exploration and assessment of combined chemical EORs at the field scale, and which can be driven dynamically to simulate realistic field applications.
In this paper we propose a set of integrated models for polymer-brine, surfactant, alkaline and foam including ions exchange for calculating effective salinities. These models can be driving by a set of flexible field management functionalities which allow a dynamic optimization of the use of the chemicals to maximize oil contact and ultimately its recovery.
A work flow to assess the balance of viscous, capillary and gravity forces involved in the EOR process is proposed to pre-screen the type of chemicals needed to modify the force balance. This approach will precede and guide the dynamic optmization.

Introduction
Exploration for hydrocarbons is reaching global frontiers, and the short- and long-term challenges will be to maximize recovery from existing fields. As an important subset of the enhanced oil recovery (EOR) offering, chemical EOR techniques have developed as an economical and viable alternative for increasing oil recovery. Their success though relies heavily on a thorough understanding and ne-tuning of the chemical interactions between the injected chemicals, the fluids in place, and the rock. These interactions eventually determine optimal injection and production scenarios and ultimately the total increment in oil recovery.
Modeling of processes such as alkaline-surfactant-polymer (ASP) flooding, low salinity water flooding, solvent flooding, and foam injection for gas mobility control require a detailed description of the EOR agent interaction with the rock and reservoir fluids. This includes flexible modeling of solution viscosities, non-Newtonian behavior,
permeability reductions due to adsorption (e.g. in polymer flooding), capillary de-saturation effect due to decreasing oil-water interfacial tension, chemical losses to the formation due to adsorption, change of wettability characteristics, and chemicals degradation, to mention just a few.
However, the success and cost-effective design of EOR projects relies on the ability to model complex combinations of these processes in realistic reservoir settings while taking into account limitations in surface equipment, project economics, and consistency in the numerical solution. Being able to monitor the chemicals within the reservoir and being able to adapt the injection and production schedule automatically become key elements in optimizing chemical EOR processes.
A High-Resolution Chemostratigraphy Application in Carbonates. A case study in the Cretaceous Mishrif reservoir, Minagish Field, Kuwait
Authors: Gezeeri Taher Mohd Nabil , Hamim Ahmed Ibrahim , Zereik Rachad , Hughes Simon Nicholas , Scheibe Christian 
Published: March 2015

Abstract
The Upper Cretaceous Mishrif reservoir in Minagish field is currently being developed by Kuwait Oil Company (KOC) using a horizontal drilling program. The Mishrif reservoir is approximately 300 ft thick across the field, with an average net pay of 170 ft in the upper layers. The reservoir porosity varies from 15 to 30%, and permeability ranges from 0.001 to 17mD. The first Mishrif horizontal well was drilled from west to east in the northern block of Minagish field. The well appears to have penetrated several generations of faults and associated fractures (early northwest to southeast, intermediate northeast to southwest, and possible late northwest to southeast. The production rate has been poor (approximately 500 bbl oil per day). An evaluation of the image logs indicated that only two of the reservoir layers appear to be fractured, whereas other layers are muddy and devoid of fractures, even near faults. To address the structural and stratigraphic uncertainties of the Mishrif reservoir, a high-resolution elemental chemostratigraphy study was performed on cored wells prior to additional drilling. The study produced a robust elemental zonation primarily based on variations in CaO/MgO, CaO/Sr, and MgO/Sr (carbonate-related), SiO2/Al2O3 and Zr/TiO2 (detrital-related), and Br, S, Na2O, and Cl (diagenetic phases and/or formation waters). The study results were used to calibrate a portable laser-induced breakdown spectroscopy (LIBS) instrument, which was used for near real-time chemostratigraphy at the wellsite to assist in geosteering operations. The recent horizontal well penetrated a highly faulted section in Mishrif layer 2, with significant changes in dip related to faults. LIBS technology assisted in actively optimizing the well path in the porous limestone zone, only 5 to 10 ft thick, within this structurally complex regime. The distribution of possible fracture swarms and faults was reflected by abrupt changes in the geochemical profiles (MgO/CaO, S, [Ni+V+Fe2O3]/Al2O3, Na2O, and Cl). This well achieved a new record for the longest horizontal drain hole in Kuwait.
P-wave Seismic Azimuthal Anisotropy for Detection and Prediction of Fractures in a Middle Eastern Carbonate Reservoir
Authors: Zelewski Gregg , Lu Chih-Ping , Tsenn Michael C. , Mitchell John , DeGraff James Michael 
Published: March 2015

Abstract

Summary
Management of carbonate reservoirs often needs to go beyond characterizing matrix properties to include fault and fracture effects, which can significantly impact water break-through and oil sweep efficiency. Predicting the flow impact of faults and fractures can benefit from the identification of these features from seismic data. Given their anisotropic nature, fracture trends in carbonate reservoirs have a reasonable chance of being detected with seismic methods. We will present the use of P-wave prestack seismic azimuthal anisotropy inversion for the detection and prediction of fractures in a Cretaceous Middle Eastern carbonate reservoir.

Introduction
The study of azimuthal anisotropy using prestack P-wave seismic was shown to be useful in the identification of open fractures by Lynn et al, 1996. More recent work in Middle Eastern carbonate reservoirs, using prestack P-wave seismic for estimating azimuthal anisotropy to detect fractures, was done by Luo et al., 2005, Holmes and Thomsen, 2002, and Roberts et al., 2001.
Open fractures in the subsurface, when vertical and aligned, may be detected with seismic anisotropy using azimuthal AVO inversion of P-wave data. The azimuthal AVO inversion method presented here is based on Ruger's equation (Ruger and Tsvankin, 1997), which describes the observed reflectivity (R) as a function of normal incidence amplitude (A0), AVO slope (B0), anisotropy magnitude (B1), anisotropy orientation (f0), and noise (ni):
R(?i , fi) ~ A0 + [B0 + B1 cos 2(fi - f0)] sin2 ?i + ni
Inversion of Ruger's equation yields four attribute volumes (corresponding to A0, B0, B1, and f0). Additionally, we developed a confidence term for uncertainty analysis.
Accurate generation of seismograms on fractured reservoirs
Authors: Thore Pierre , Tarrass I. , Gibson Richard L. , Lisitsa Vadim V. , Reshetova Galina V. , Tcheverda Vladmir A. 
Published: March 2015

Abstract
A major challenge in carbonates environments is to map heterogeneities which have a strong impact on oil and gas production. For example in many carbonate reservoirs, matrix porosity contains the oil in place but the permeability is mainly provided by fracture corridors. In some carbonate reservoirs, such as Kashagan field in Kazakhstan, the oil in place is essentially contained primarily in karstic caves and conduits. Therefore being able to precisely locate these heterogeneities and possibly characterize their properties is essential in these environments.
Various techniques have been developed recently to locate and characterize these heterogeneities, by detailed analysis of the elastic signals recorded in seismic experiments. Among them one can think of the scattering index presented by Willis et al (2004) or all the imaging techniques developed recently under the generic name of interferometry.
The first step in all processing or inversion procedures is to be able to accurately simulate the forward problem, and it is therefore of paramount importance to be able to accurately model the scattering related to fractures and caves. The numerical and computer constrains even on very large clusters limit the resolution at which a model can be described. The current practice for finite difference modeling is to use 20m grid cells for acoustic modeling and spatial discretization leading to cells 10m in size for elastic modeling. In these cases, heterogeneity associated with fracturing on smaller scales must be upscaled and distributed in an equivalent medium, which will reproduce varaiations in traveltimes and changes in reflection coefficient but will neglect the scattered wavefields that are the subject of the recently developed methods for characterizing fracture distributions. In this paper, we present a full waveform modeling technique based on a new approach of finite differences which allows simultaneous simulation of both macro- and micro-scale heterogeneities. This algorithm is based on a multi grid approach that models the seismic response of a shot point over a large size model containing micro scale heterogeneities in a reasonable time frame (i.e., several hours on a modern cluster). We show various examples of the signals related to fractures and their importance in terms of heterogeneities interpretation, and we also examine results of simulations using 3-D modeling based on the Born approximation to help interpret and explain the synthetic seismograms.
These new numerical results will have significant advantages over previous results that rely on approaches that replace the detailed spatial variations of elastic properties with media with altered velocities and densities.
Correlation between Rock Physical Properties, Sedimentological, and Diagenetic Characteristics of Late Cretaceous Carbonate Rocks in the Middle East
Authors: Alsuwaidi Mohammad Eid , Vega Sandra , Steuber Thomas 
Published: March 2015

Abstract
This paper aims to establish correlations between petrophysical properties, sedimentological, and diagenetic characteristics of carbonate rocks from well cores of the Lower Cretaceous Thamama Group. A previous petrophysical study by Saleh, et al (2008) on the same well cores revealed that four plug samples out of 17 have a strong anisotropy relation of shear velocity (Vs) and permeability. Based on these results, we conducted a thorough sedimentological and petrographical study to explain the unique characteristics of these samples.
We performed a full 170 feet core description of a vertical well to study the lithological and diagenetic background of the seventeen samples. It was assured that the core plug samples represent all types of lithofacies observed in the core description. Thin sections from the samples were also prepared and described, and well log data were analyzed.
The well core description resulted in the identification of five lithofacies: bioclastic wackestone with low cementation, Bacinella floatstone, requieniid rudist floatstone/rudstone, highly cemented orbitolinid wackestone/packstone, and thin bedded shale.
Three out of four samples, that have Vs and permeability anisotropy relationship, belongs to the bioclastic wackestone. The fourth sample belongs to the requieniid rudist floatstone/rudstone. It contains dominant matrix and scattered requieniid rudist fragments.
Thin section description showed that samples with anisotropy relation of shear velocity and permeability are characterized by: a pore system that is homogenously distributed (microporosity), without significant influence of cementation, abundance of allochems, and other type of porosities, abundance of matrix, lack of skeletal and non-skeletal allochems, and low cementation. On the other hand, samples that have no clear anisotropy relationship have abundant bioclasts are highly cemented and have dominant intraparticle, interparticle, vuggy, or channel porosity.
Crossplot analysis of well logs and core description gave the following results:• Core horizontal permeability and porosity correlation has three main trends interpreted according to different degrees of cementation.• In general, as horizontal permeability of core increases, the compressional wave velocity decreases twice as much as the shear wave velocity, taking into account the preferential permeability direction.
Inline separation pilot to support Produced Water Injection in PDO
Authors: Verbeek Paul , Al-Moosani Ashiq 
Published: March 2015

Abstract
This paper describes a technology development project that resulted in the deployment of a fully operational in-line/compact separation prototype skid, which is the first of its kind in the industry. The project provided the surface facilities necessary to successfully arrest the decline of production in a North Oman oil field through Produced Water Re-Injection in a timely manner. The modular approach proves to be a concept that may satisfy the needs for cost effective improved oil recovery in onshore and offshore remote production locations.
First Time Application of Stand Alone Screens with Sliding Sleeves in the Giant Mangala Field, Rajasthan India
Authors: Chavan Chetan Harish , McKenzie Tim , Wenk Andrew D.G. , Tandon Rohit , Bhat Suniti 
Published: March 2015

Abstract
This paper describes the first time selection and successful application of Sliding Sleeve Sand Screens in the open hole completions of the giant Mangala field situated in the Barmer Basin in Rajasthan, India which holds ~1.2 billion barrels (bbls) of oil in place.
The field is a multilayer reservoir and has waxy viscous crude with in-situ oil viscosity up to 17 cp. The field is being developed with a hot water flood for pressure maintenance and reservoir sweep. Significant production challenges include; an unfavourable mobility ratio, early water cut, sand production and high pour point.
Production well completions with sand screens with sliding sleeves play an important role in the field development, providing a very flexible tool to manage production from individual sand units coupled with open hole sand control. The screens are installed as an open hole completion and swellable element packers provide annular flow control. Intervention costs are kept low, as the field is onshore and the opening / closing of the sliding sleeves are done with relatively cheap onshore well intervention via slickline.
Active reservoir surveillance and management in Mangala field will play a key part in maximising reserves and production rates from the field. Sliding sleeve sand screens are an appropriate technology for the Mangala field oil wells. These screens provide options for downhole water control across the formation thus increasing well life and reducing water handling at surface.
This paper describes the design and implementation of these completions and how the completions provide optimum reservoir management capability for the Mangala field.
Breaking Oil Recovery Limit in Malaysian Thin Oil Rim Reservoirs: Water Injection Optimization
Authors: Chan Keng Seng , Kifli Azmukiff Muhammed , Darman Nasir B. 
Published: March 2015

Abstract
The goal of an oil field development project is to accelerate the hydrocarbon production and maximize the recovery at a lowest cost. For a thin oil rim reservoir with a large gas cap on top and a strong aquifer below, achieving such goal can be very challenging since recovery of both oil and gas shall be maximized. A successful project shall entail plan first to accelerate the oil production maximizing the oil recovery prior to the gas cap blow-down.
The maximum oil recovery factor achievable in thin oil rim reservoirs was evaluated for a Malaysian thin oil rim reservoir. The force balance between the gas cap expansion, aquifer expansion and viscous withdrawal was demonstrated by showing the model simulated water-oil and gas-oil contact movement. The understanding of the force balance progressively guided the field development project team to selectively re-activate some of the idle wells, to selectively place new additional infill horizontal wells, and to plan selective water and gas injection in key reservoir sectors.
In this paper, the concept and strategy of water injection for a subject thin oil rim reservoir was delineated. Placement of a system of water injectors at the selected sector periphery and at the gas oil contact was studied.
Together with optimization of infill well placement and the selected idle well reactivation, this effort showed a potential of improving the current recovery factor from 35% up to 51%, way beyond the maximum theoretical vertical displacement efficiency. In addition, it can be shown that successful water injection can improve productivity of production wells due to increasing near wellbore oil saturation.

Introduction
For thin oil rim reservoirs in Malaysia, the key force balance is between the gas cap and aquifer expansion, and the fluid withdrawal by well production, in addition to the capillary and gravitational forces. The understanding of the force balance in the reservoir will lead towards a better optimization of reservoir oil and gas production, achieving a higher recovery factor, and generating a good investment plan (Ref. 1).
The study in this paper will focus on the Seligi field in Malaysia. It is located offshore Terengganu and was progressively developed starting in 1978 as an oil field. It is a combination of stratigraphic and heterogeneous structural traps (Figure 1). It has a huge regional aquifer and 5 distinctive gas caps (Figure 2) at the time of discovery/development with a significant amount of oil in place (Ref. 2).
Seligi field was developed with the concept of produced gas re-injection at the gas caps. Typically, 75% of the produced gas was re-injected via 15 gas injectors at the 5 gas caps. However, the subject oil rim reservoir pressure has been declining gradually as oil being produced (Figure 3).
Perturbation of Homogeneous Thermal Conductivity Distribution in Some Carbonates by Stylolites
Authors: Padmanabhan Eswaran 
Published: March 2015

Abstract
Stylolites are partings within rocks that exhibit complex mutual column and socket interdigitization. These features can exhibit pronounced roughness on several scales. Stylolites, under deep-burial conditions, could permit circulation of undersaturated fluids and become reservoirs allowing also deep commercial gas production. However, the impact of stylolites on variations in thermal conductivity in carbonates is not well-known. This study was undertaken to investigate the heterogeneity in thermal conductivity in a variety of carbonate specimens containing different types of stylolites.
A total of 9 carbonate samples from Turki were used in this study. These sampes were imported into Malaysia by a local factory. The stylolites were classified into three types. Type 1 (sharp-peak) has well defined and high density (4 amplitudes per cm) fractures. Type 2 (simple wave-like) is intermediate whereas type 3 (sutured) has poorly defined and low density (&lt; 1 amplitude per cm) fractures. The thermal conductivity of type 2 (mean = 3.30 W m-1K-1) was the highest and that of type 3 (mean = 1.35 W m-1K-1) was lowest. Similar trends were recorded for non-stylolitic faces of the three carbonates specimens mentioned above. Faces with stylolites showed a high degree of variability in terms of thermal conductivity when estimated at various points. Surfaces with stylolites tend to show different thermal conductivity values than non-stylolitic faces. The reduction in porosity, type of stylolite and a possible effect of different orientation of the carbonate minerals in the stylolites, appears to perturb the homogeneous distribution of thermal conductivity in these carbonates.
The study indicates that thermal conductivity estimation is point-dependant. The perturbations created by the stylolites would result in spatial variations in thermal conductivity with possible implications of differences in thermal maturation of hydrocarbon resources at the micro-site levels.
A Reservoir Management Tool for an Omani Fractured Carbonate Reservoir _ A Case Study
Authors: Al-sinani Ibrahim Said , Al Maamari Rashid Salim , Al-wadhahi Majid Ahmed , Paino Wan Faisal 
Published: March 2015

Abstract
This paper presents a case study of developing a reservoir management tool (a water coning correlation) to monitor the oil rim thickness and position in a giant densely fractured carbonate reservoir in Northern Oman. The production mechanism in the field is Gas Oil Gravity Drainage (GOGD), with crestal gas injection to maintain the reservoir pressure and dedicated aquifer pump off wells to control the oil rim position.
As the field is produced from a thin oil rim in the fractures network primarily through open-hole horizontal wells, it is crucial to keep the oil rim fixed and at such depth and thickness so that coning and cusping of water and gas into the oil producing wells is minimal.
In this study, two approaches; analytical and numerical were used to develop a correlation between produced water rate and distance of the measured Fracture Oil Water Contact (FOWC) from the well perforations. From the numerical simulation model, a correlation between the water rate produced from a horizontal well in a fractured reservoir and the distance between the FOWC and the well perforations was developed. The developed correlation from the simulation model couldn't be correlated with measured contacts data due to the improper fracture connectivity between the observation wells and the oil producers. However, a reasonable match was obtained between the fluid contacts from the developed correlation and the estimated contacts using the measured gas and water pressure data. The developed correlation could be further improved by incorporating the fine fracture details around the well in the simulation model.
This correlation could be used on a monthly basis to estimate the location of FOWC nearby the oil producer from the tested water rate. This will yield a better oil rim management by monitoring the rim position and thickness regularly and therefore produce the field at optimum oil rate. This correlation will also minimize the need for direct measurements of the contacts using the gradiomanometer surveys and hence reduce the operational cost.

Introduction
Reservoir management becomes an important and challenging aspect in mature highly fractured oil field reservoirs. One of the main challenges in the management of dual permeable (fractured) reservoirs is water coning through the fractures. This issue becomes more serious in carbonate reservoirs (long open fractures) with strong aquifer support.