bluuebunny/crossref_metadata_2025_split huggingface dataset:
Carbon Dioxide Geological Sequestration: Technical and Economic Reviews
Authors: Nguyen Duy Nghia 
Published: December 2007

Abstract
Geological sequestration is a potential technology to reduce large amount of greenhouse gas emissions which are essentially carbon dioxide (CO2) released from stationary industrial sources such as petroleum extractive plants or fossil-fired power plants. Sequestering CO2 from a natural gas development involves separating CO2 from hydrocarbon gases, dehydrating and compressing CO2, transporting it via pipeline to injection site, re-compressing if applicable, injecting it into geological reservoirs and monitoring its movement and behaviour after sequestration. Chemical absorption using amines is the most widely used technology to date for separating CO2 from natural gas. Current researches focus on other technologies, especially membrane technologies. Reservoir and geology studies are to optimize the sequestration process and to predict the movement of the injected CO2 in the reservoirs. Monitoring the injected CO2 after sequestration is to ensure that CO2 is retained in the reservoirs.
The costs of sequestration could vary from below US$5 to over US$20 per tonne of CO2, which largely depends on the amount of CO2, distance and reservoir properties. Economic results are in favor of large CO2 flow rate, short distance and high injectivity reservoirs. These costs exclude the separation costs which are considered to be part of the natural gas processing because CO2 must be reduced to a certain level (e.g. 2% by volume) before selling the natural gas even if no sequestration is needed. Cost per tonne of CO2 sequestered could be translated into the incremental costs of producing natural gas if we know the CO2 volume fraction in raw natural gas. For instance, as a rough estimate, sequestering the CO2 from a 25% CO2 by volume raw natural gas field would increase the costs of natural gas production by US¢9/Mcf to US¢35/Mcf of processed natural gas.
Biological and Volatile PAH Losses During Aerobic Slurry Phase Biotreatment
Authors: Fairey Julian L. , Loehr Raymond C. 
Published: December 2007

Abstract
The suitability of an aerobic biological treatment process for the removal of PAH from a creosote contaminated field soil was evaluated. Specific objectives were to determine: a) the overall loss of specific PAH, b) losses due to volatilization, c) the effect of possible operating temperatures and microbial acclimation, and d) the relationship between volatile losses and solid-liquid and liquid-gas partition coefficients. The results indicated that an active aerobic biotreatment process is a suitable treatment process for these contaminated soils. Overall losses that occurred were: 2-ring PAH, 99-100%; 3 ring PAH, 86-100%; 4 ring PAH, 41-44%; and 5-ring PAH, 26-37%. There was little difference in PAH removal at 20°C and 35°C. Volatile PAH losses did occur. The maximum PAH loss was for naphthalene and ranged from 9 to 17%. For most of the other PAH, overall volatile losses were less than 1% and commonly in the 0.1 to 0.9% range. There were no volatile losses for some of the 4 ring PAH and for all of the 5 ring PAH that were measured. Volatilization became less of a factor as microbial acclimation occurred. The study documented that, in an aerobic treatment process with an active acclimated microbial population, microbial degradation of SVOC will be the primary loss mechanism. Several predictive relationships were determined between PAH volatile losses and liquid-gas (KH) and solid-liquid (KOW, KOC) PAH partition coefficients.
Ultra Short Radius Drilling Trials in PDO
Authors: Al-Hady Abdullah Saif , LaPrad David , Al Sadi Anwur 
Published: December 2007

Abstract
Productivity from thin reservoir layers and thin oil rims can be enhanced by short laterals, fully contained within the layers. Ultra short radius system will be required to kick off and drill these lateral within the reservoir. Now days, these system are available as Rotary Steerable system 4-8 m and jetting system (0.5 m). This paper will discuss the flexible pipe rotary system, in particular the Torch drilling services (TDS) system and the implementation of this system in PDO.
This system has been tried two times last year in Lekhwair field. In both wells a dual lateral have been drill and completed as open hole injector. The paper will discuss this the technology concept, describe the tool and drilling procedure and will summarize the operational aspect of the trial. Couple of trials will be planned this year (2003) to complete the evaluation of the system.
Gas Migration After Cementing Greatly Reduced
Authors: Jennings Scott S. , Al-Ansari Adel A. , Al-Yami Abdullah S. 
Published: December 2007

Abstract
Gas migration through cement columns has been an industry problem for many years. The most problematic areas in Saudi Aramco operations for gas migration are in deep gas wells (Khuff / pre-Khuff) in the Ghawar field.
Gas migration in deep gas wells occurs when drilling through the base of Jilh dolomite. To control gas influx, cement densities required to successfully cement this zone could be as high as 170 pcf. Specially designed cements were used to "zone isolate" the high pressure coming from the formation. High density/low fluid loss cements were used in the past with limited success. More recently, Liquid Latex in combination with expanding additives have been used to help reduce the gas flow potential before and after the cement sets.
The objective of this study was to develop effective cement formulations to control deep gas migration during primary cementing and optimizing costs of expensive cement additives. Three major physical properties lab equipments were utilized for this study. First, a cement gas migration system (CGMS) was utilized to measure gas flow through a cement column prior to the setting of the cement. Second, the static gel strength analyzer (SGSA) was used to determine the static gel strength of well cements to confirm the data from the CGMS. Third, the American Petroleum Institute (API) expansion cell was used to determine the expansion properties of set cements. Data from the CGMS, SGSA and API expansion cell was successfully utilized to greatly reduce the gas migration problem. The consumption of expensive cement additives (latex and expansion) in the cement formulations were optimized for cementing gas wells with success. The in-house cement design optimization saved the company as much as 59% on the cost of obtaining the desired cement fluid properties.
Reservoir Simulation of Gas Injection Processes
Authors: Lawrence J. J. , Teletzke G. F. , Hutfilz J. M. , Wilkinson J. R. 
Published: December 2007

Abstract
In reservoirs with favorable rock and fluid properties, application of gas injection processes can enhance the recovery efficiency and value of a field development. ExxonMobil employs a systematic approach to evaluating and selecting recovery processes during the full life-cycle of each reservoir. Once a gas injection project has been implemented, ongoing surveillance programs and optimization studies are performed to ensure that maximum value is obtained from the resource. One important aspect of managing these resources has been the use of reservoir flow modeling to understand performance expectations and to develop reservoir management strategies to optimize recovery.
Because ExxonMobil's experience with reservoir simulation of gas injection processes has covered many types of injection processes over many years, a full suite of simulation approaches has been used for reservoir flow modeling. The gas injection processes studied and implemented have included miscible floods, immiscible floods, Water-Alternating-Gas (WAG) floods, as well as gas disposal. A full range of injection gases such as CO2, H2S, N2 and hydrocarbon injectants has been used. The fit-for-purpose simulation approach is chosen based on specific needs and objectives for each reservoir. The approaches have ranged from coarsely-gridded black oil simulation to finely-gridded compositional simulation depending upon the specific requirements for a given field. In recent years, the emphasis has been on state-of-the-art compositional simulation. ExxonMobil has applied compositional simulation to design and manage more than 25 gas injection projects covering the full range of injectants and lithologies.
Because each gas injection project is unique, the evaluation of benefits must be comprehensive and adaptable. Case studies are presented illustrating a range of gas injection processes and reservoir types. The case studies highlight important aspects of data collection, issue identification, simulation technique evaluation, process evaluation, and long-term project stewardship.
Water Injection and Water Flooding Under Fracturing Conditions
Authors: Noirot J. C. , van den Hoek P. J. , Zwarts D. , Bjoerndal H. P. , Stewart G. , Drenth R. , Al-Masfry R. , Wassing B. , Saeby J. , Al-Masroori M. , Zarafi A. 
Published: December 2007

Abstract
With the realization that water injection is generally taking place under fracturing conditions, tools capable of better modelling fractured injection and its impact are being developed. Models integrating rock (fracture) mechanics and traditional reservoir simulation are now applied to water injection projects with a number of applications in the Middle East. Fracture dimensions are a key input to those models. Monitoring techniques to track the evolution of induced fractures with time are also being deployed. Amongst those techniques microseismic and specific fall-off test procedures are used.
A Simple, Robust Interpretation Method for Matrix Acidizing Treatments – Part 1: Theoretical Basis and Field Example
Authors: Chan Keng S. , Flamant Nicolas C. , Helou Husam N. 
Published: December 2007

Abstract
During matrix acidizing operations performed on oil wells, post-treatment analysis is often overlooked due to the lack of a simple, robust tool. Current methods rely on the equations used for well tests analysis, either steady state or transient, and focus on the computation of the skin factor. However this computed skin most often proves unreliable due to the complexity of the treatments, which routinely involve multi-layered reservoirs and advanced diversion techniques, i.e. phenomena that are not handled by the well testing equations. As a result, operators content themselves with providing clients with a plot of pump rate and wellhead pressure versus cumulative volume - or time. Unfortunately, any interpretation performed with this type of plot has more in common with divination than science.
In this paper, a new way to plot matrix acidizing treatment data is presented. The inverse injectivity index and its integral are plotted versus time. This is similar to Hall plots, which are used to monitor water injection wells, but it corrects for the rate changes occurring during acidizing treatments. The concavity of the integral then visually indicates whether the treatment is achieving stimulation or diversion, and this behavior can easily be identified despite the noise usually associated with any field measurements. As a side benefit, this technique also provides means to verify the average reservoir pressure value.
The theoretical basis of this new plot is discussed and its usefulness assessed using data generated by Pericles, a matrix acidizing numerical simulator. A field case is then analyzed and is used as an opportunity to once again emphasize the need for reliable bottom hole pressure data, whether measured or calculated, without which any analysis is inherently flawed.
Patterns of Variation of Permeability Anisotropy in a Carbonate Reservoir
Authors: Sahin A. , Menouar H. , Ali A. Z. , Saner S. 
Published: December 2007

Abstract
Most classical reservoir engineering concepts are based on homogeneous reservoirs despite the fact that homogeneous reservoirs are the exception rather than the rule. This is especially true for the Middle-eastern carbonate reservoirs, which are known to be highly heterogeneous. The realistic characterization of such types of reservoirs is not an easy task and must include the study of directional variation of permeability. The latter is incorporated in engineering calculations as the square root of the ratio of horizontal to vertical permeability, a parameter known as the anisotropy ratio. Approximate estimates of this ratio are often used in practice despite the fact that it is a crucial parameter in hydrocarbon production.
This paper addresses the pattern of variation of the anisotropy ratio in an Upper Jurassic carbonate reservoir located in Eastern Province of Saudi Arabia. Based on whole core data from several vertical wells, statistical distributions of horizontal and vertical permeability measurements as well as the anisotropy ratios were determined. These distributions for each well are characterized by a considerable amount of positive skewness. A comparison of the values of anisotropy ratios along the wells indicates that, except for a few extreme values, a certain amount of uniformity exists among the ratios for each well. However, lateral variations in the anisotropy ratios are frequently observed. This study also indicates that higher fluctuations in the anisotropy ratios can be correlated with low porosity intervals existing within the reservoir. Three statistical techniques, based on the arithmetic, geometric and harmonic means, and commonly used for combining permeability measurements, have been proposed for combining the anisotropy ratios.
Permeability and RRT Estimation from Conventional Logs in a Middle East Carbonate Reservoir Using Neural Network Approach
Authors: Karri Suryanarayana , Al Amari Khalid , Vissapragada Badarinadh 
Published: December 2007

Abstract
A complex carbonate reservoir of a giant on-shore structure in central Abu Dhabi consists of a porous limestone section divided by several stylolitic dense layers. The reservoir is heterogeneous. High and low permeability rock types co-exist without much variation in log characteristics. Permeability changes several orders of magnitude with no appreciable change in porosity. Reservoir rock types and permeability measurements are available from 30 cored wells. The reservoir is penetrated by more than 100 vertical wells where open hole logs of various vintages are available. Estimation of permeability using conventional logs in the intervals and wells where core data is not available has been a challenge for many years. In this study, relationships were built between core data and the open hole log suite using the Artificial Neural Network approach and were used in estimating reservoir rock types and permeability.
A typical character of the reservoir is that the log signatures are similar for several dissimilar rock types. Due to limitation on the vertical resolution conventional open hole logs alone could not differentiate these rock types. A synthetic variable cementation exponent ‘m' curve, gradient curves from Gamma Ray, Bulk Density and Neutron porosity logs supplemented the open hole logs in the neural network analysis in resolving the permeability variations. Nine neural networks were constructed to handle the complexity. Robust reservoir rock type and permeability estimation was achieved in two iterations. In the initial pass, fractional facies curves were estimated using a supervised classification network. These fractional facies curves were then used in initial permeability estimation with the help of a supervised estimation network. In the next pass, this permeability curve was used to estimate the reservoir rock types. In the final step, to fine-tune the magnitude of the permeability, the log derived reservoir rock types were included in network analysis and a final permeability curve with improved magnitude was generated. The initial permeability estimation was made separately on two vertical sub divisions of the reservoir interval and the reservoir rock type estimation was made on four separate vertical sub divisions based on the occurrence of various RRTs.
Examples are provided showing a satisfactory prediction of both RRTs and permeability in cored and non-cored wells. The estimated permeability and RRTs were incorporated in the 3D geological model supplementing core data.
ESP Failures / Analysis / Solutions in Divided Zone - Case Study
Authors: Mubarak Hisham A. , Khan Farooq A. , Oskay Mehmet M. 
Published: December 2007

Abstract
This paper presents the performance of Electrical Submersible Pumps (ESPs) in the Wafra field within the Divided Zone Kuwait-Saudi Arabia and covers the period of 4 years started in 1998 - December 2001. Included are the historical failures of ESPs, analysis of failures and some solutions that have helped to reduce the number of failures and that in-turn increased ESP run lives/reduced deferred oil production/saved rig cost/time.
Main reservoirs in the DZ area producing with ESPs include Wara/Burgan sands and Ratawi carbonates. Some ESPs are also operating in heavy oil carbonate Eocene wells, Ratawi limestone in south Fuwaris and Marrat carbonate in Humma field. As these reservoirs are of different lithologies, depths and flow rates vary from 1,000 to 9,000 bfpd, thus all series/types of ESPs have been run.
Tables and plots demonstrate/analyze total number of ESP failures by each reservoir / equipment / components types, mean time to failure (Average Run Life), ESP listings. In summary, it is shown that ‘Mean time to failures’ (Average Run Life) significantly increased from 157 to 370 days within this 4 year period.
ESP completions in Wara sands presented the biggest challenge to reduce ESP failures due to high sand volume erosion. New material design for ESP defined as ARM-COMP "Abrasion Resistance Material- Compression" was utilized successfully. In other reservoirs, new designs of ‘Slim Hole’ ESPs, ‘Shrouded Motors’, ‘Pump Optimizations’, ‘Stimulation jobs to increase intake pressure’ have been used to overcome frequent burnt motor, pump plugging etc., problems. Also, ESP XGC Gas Handler for high GOR wells was successful.

Introduction
Divided Zone Group (DZG) pursue exploration and optimum development of hydrocarbon resources of the Divided Zone (On-Shore) through Joint Operations (JO). The Divided Zone field is producing using artificial methods (Sucker rod pump & Electrical submersible pump). The focus of this paper is on the performances of electrical submersible pumps in period of 4 years started in 1998 until Dec.2001.
Main producing reservoirs in the DZ area include Wara/Burgan sands and Ratawi carbonates. Some ESPs are also operating in heavy oil carbonate Eocene wells, Ratawi limestone in south Fuwaris and Marrat carbonate in Humma field. As these reservoirs are of different lithologies, depths and flow rates vary from 1,000 to 9,000 bfpd, thus all series/types of ESPs have been run.
The total number of ESPs installed at the end of year 2001 in DZ was 251 and the common reasons of ESP failures and approximate percentages are:Motor Failures (40%)Pump Failures (22%)Cable Failure (26%)Others (12%)
The following case studies for wells in Ratawi and Wara Reservoirs will be presented. These wells had ESP failures either due to high GOR or excessive sand production.Slim hole pump - Ratawi Reservoir - Case1.Shroud Motor & XGC gas handler- Ratawi Reservoir - Cases 2 & 3.Abrassion Resistance Material (Floater&Compression)-Wara Sand Reservoir Case 4 & 5.
A Full Field Simulation Model of a Giant Cabonate Reservoir in Kuwait
Authors: Matar Saad , Al-Medhadi Fahad , Meadows David , Al-Ajmi Hamad , Oosthuizen Ulrich R. 
Published: December 2007

Abstract
The Minagish Oolite is a thick undersaturated carbonate oil reservoir in the Minagish field in West Kuwait (Fig. 1) containing several billion STB. It is a mature but relatively undeveloped reservoir. Since discovery in 1959, it has produced 10% of its OOIP under a combination of natural depletion, gas re-injection and aquifer drive. Initial reservoir pressure had declined by about 450 psi prior to the Gulf war in 1990. The well blowouts following the war caused a significant pressure drop of another 700 psi. Following the blowout, plans were made to redevelop the West Kuwait fields and increase the production rate starting in 2001 and to sustain the plateau for at least 5 years. This strategy called for threefold increase in the production rate of Minagish Oolite reservoir. Since the existing well inventory and the loss of the gas re-injection facility could not sustain the desired plateau rate, additional field development was required.
To achieve the production target, a multidisciplinary team was formed to evaluate options. The recommended plan required the drilling of additional producers and installing a field-wide peripheral waterflood. The reservoir, however, presented a number of significant challenges to waterflooding, such as the presence of a substantial and not well defined tarmat near the oil/water contact, and uncertainties of lateral and vertical heterogeneities. In 1997 a full-field simulation model was developed, but this model didn't capture the water movement properly because of insufficient reservoir data at that time. As new core was obtained, a refined reservoir description was developed. Building on lessons learned from the previous full-field model and sector models, a new full-field model was developed which significantly improved well-by-well history matches. Although containing twice as many grid cells, the new model ran up to four times faster than the previous model by making use of the Analytical Aquifer option within the model, improved relative permeability curves and other model refinements.
This paper traces the history of the field and the systematic evolution of the development plan. The reservoir simulation efforts including modeling strategy, history matching events, prediction runs, future direction and challenges are also addressed.
Numerical Simulation of Non-Darcy Flow Utilizing the New Forchheimer's Diffusivity Equation
Authors: Belhaj H. A. , Agha K. R. , Nouri A. M. , Butt S. D. , Vaziri H. F. , Islam M. R. 
Published: December 2007

Abstract
Recently, it became evident that non-Darcy flow occurs not only in gas reservoirs, fractured reservoirs and multi-permeability systems within oil reservoirs experienced non-linearity due to non-Darcy flow behavior. Most reservoir simulators currently used encountered false predictions due to their dependency on the traditionally used diffusivity equation.
This paper introduces alternative diffusivity equation to replace the one derived from Darcy's law. The new equation was derived from the commonly known as Forchheimer's equation which is basically Darcy's equation plus an inertia term to account for high velocity fluid flow in porous medium.
Mathematical derivation of the diffusivity equation based on Forchheimer equation has been presented in a previous paper by the authors.
The newly derived diffusivity equation has been numerically simulated. Correlations used to estimate the non-Darcy coefficient "β" have been comprehensively reviewed; nine correlations found suitable for use in this study for technical reasons. A new dimensionless number (Be) relating β, velocity, density and viscosity has been introduced to differentiate between Darcy and non-Darcy flow in porous medium for any rock type and any flowing fluid. Evidences show that this new dimensionless number cannot be considered a declaration of turbulence flow in porous medium rather the energy loss is contributed to the nature of both flowing fluid and the porous medium. The point of deviation from the Darcian behavior to the non-Darcian behavior has been found at Be = 0, for practical use it has been determined that Be = 0.0526 at 5% deviation from Darcy's linear trend.
A range of permeability from 1 md to 1000 md with porosity changing accordingly has been verified with the new model, velocity as low as 0.0001 cm/sec and as high as 700 cc/sec has been tested as well. Both Darcy and non-Darcy behaviors have been identified for the domain of testing, and the numerical model has proven of good agreement in all cases.