bluuebunny/crossref_metadata_2025_split huggingface dataset:
Methodology to Incorporate Geological Knowledge in Variogram Modeling
Authors: Bahar A. , Ates H. , Kelkar M. , Al-Deeb M. 
Published: December 2007

Abstract
Geological knowledge is an important ingredient in a successful reservoir characterization process. Geoscientists and engineers have used variogram extensively as the tool to quantify the spatial relationship of various attributes, e.g., facies/rock type, porosity, and permeability. Proper variogram modeling is a key factor to obtain a geologically-sound reservoir characterization model. This paper discusses the difficulty that is commonly encountered by many practitioners in modeling the variogram and proposes a way to incorporate geological knowledge as the soft information to improve variogram model.
Common difficulty in variogram modeling is the calculation of horizontal variogram. The averaging technique that uses combination of geological knowledge and analogy in geophysical literature about frequency data analysis is implemented to solve the difficulty in calculating horizontal variogram. This technique has produced results that are agreeable with geology of the reservoir.
The art of incorporating the geological knowledge in variogram modeling lies in the fact that geological knowledge is a qualitative measure whereas variogram is a quantitative measure. The methodology to combine these two measures presented in this paper is as follows. First, interpreting various geological aspects of the reservoir in detail. These include, but not limited to, the interpretations of geological environment, sequence stratigraphy, pore-space characteristics, iso-chores, iso-porosity and iso-permeability maps. From these interpretations, a summary table, that includes the major continuity direction, lateral extension and anisotropy index of each attribute, is prepared. Second, calculating experimental variogram using the Averaging Technique. Third, modeling the experimental variogram considering the information obtained from the first step.
The procedure presented above has been implemented as a routine procedure in several reservoir characterization studies for both carbonate and sandstone reservoirs in the Middle East and in the USA. For illustration purposes, comparison of the realization results, taken from carbonate field study, between the model with variogram derived purely from the hard data, i.e., well log data, and the variogram derived from both hard and soft data, i.e., geological knowledge, is presented. It is concluded that the incorporation of geological knowledge has improved the confidence level of the results and should always be part of any reservoir characterization study.
Erb West Field: The World's First Offshore Level 6 Multilateral Well
Authors: Samsudin Noren , Kassim Abdullah , Khalid M Zaidan , Rahman A. Aziz A. , Che Mad Abu Bakar , Liau Richard , Jabs Matthew , Lim Ben 
Published: December 2007

Abstract
The oil industry has lately seen the introduction of more complex, purpose built multilateral wells of the TAML (Technology Advancement Multilateral) levels 4 and 5 categories. The debris management issues, junction integrity and the risk involved in the well construction are still perceived as operational challenges to operators. In reviewing the risk profile, operators and service companies alike have sought to look into techniques outside the realm of conventional well construction methods. Expandable tubular technology is one such area. The manufacturing concept is to form a junction with a 9-5/8" trunk casing branching into two separate 7" liner legs. This junction is then pressed and formed in order for it to be able to pass through the drift ID of 13-3/8" casing. The junction is then reformed downhole using an innovative downhole swaging process.
This paper describes the process of deploying the TAML level 6 multilateral junction in the Erb West Field (offshore Malaysia) during the EWDP-A Revisit 4 Campaign (well EW-117S1). The discussion follows the full cycle of well construction for a level 6 multilateral junction. It encompasses the well planning phase, the deployment and the installation phase, the lateral drilling phase, and finally the completion of the level 6 multilateral well. The result is a multilateral well construction technique which eliminates the debris management, reduces well construction risk and provides a hydraulically sealed junction, integral with the trunk casing.
Production System Optimisation - Offshore West: The First Pass
Authors: Naizatulakmal Abdullah , Kassim Salawati Hj , Min Mook Wah , Ahmad Rosiah Hj 
Published: December 2007

Abstract
Squeezing the extra barrel of oil from a brown field asset requires a structured working methodology to maximise a field's total potential both from the subsurface and surface aspects of operations. Brunei Shell has introduced the concept with a Production System Optimisation (PSO) Team in 1997. This proved very successful and Brunei Shell has therefore taken another step towards realising the limit with the setting up of three dedicated PSO teams, one for each of the geographic operating areas. The paper will outline the ongoing efforts made by one of these three PSO teams, the "West" team, in identifying production opportunities in the offshore Ampa, Fairley and Gannet fields. The nature and scope of work that has been carried out so far includes simplification of process design, reducing deferments, realising the field's lock-up potential, removing process bottlenecks and optimising the operating envelope. This is often achieved by applying "out of the box" approaches to deliver innovative business solutions. This will be demonstrated with examples. The working methodology and key learning points outlined in the paper can easily be adopted by other oil and gas operating companies. From the PSO/1 implemented activities, an average of 320 m3/d/annum nett oil production has been delivered for the year 2000, generating revenue amounting to US$60300 per day (at US$30/barrel) and a saving of 70% on CAPEX.
Fluid Characterization of an Iranian Carbonate Oil Reservoir Using Different PVT Packages
Authors: Ghorbani D. , Kharrat R. 
Published: December 2007

Abstract
Precise and accurate characterization of a reservoir fluid is a very important factor in reservoir simulation studies. PVT experiments are usually expensive and performed in limited conditions. Therefore Computer EOS based PVT packages are used widely for the prediction and evaluation of fluid properties at reservoir, well and surface conditions over a wide range of temperature, pressure and composition1,2,3,4. In this work different PVT packages that are available in National Iranian Oil Company (NIOC) have been used to complete fluid analysis and experiment simulation of an Iranian oil reservoir and PVT model preparation for the reservoir simulators. This reservoir is a medium size, highly fractured carbonate reservoir located in southwest of Iran. The carbonate formation has dense matrix with improved permeability by presence of fracture network. This reservoir was initially highly undersaturated and after 5 years of oil production the oil pressure reached to the saturation pressure and gas injection was started into the reservoir5.
In this work different equation of states, different regression methods and correlations were analyzed for the prediction of fluid properties. Considering the results of this work in general good agreement was obtained for the experimental and calculated data for used packages. However, the method used for tuning the equation of states is critical in getting good agreement.
Hydraulic Fracture Stimulation of the BRF Clastic Formation, Ramba Field, South Sumatra Indonesia – a Case Study
Authors: Effendi Prijandaru , MacNeill George , Badri Mohammed 
Published: December 2007

Abstract
The Baturaja (BRF) Clastic Formation in the Ramba Field of South Sumatra, Indonesia must be hydraulically fracture-stimulated to produce the reservoir at an acceptable economic level. Early efforts at producing from this formation were disappointing. A combination of a detailed reservoir engineering study and developments in fracture stimulation technology has made this zone an economic success.
The detailed engineering study allowed for a better understanding of the permeability variations within the formation across the field which in turn helped in the selection of optimum placement of the wells and individually tailoring the fracture stimulation treatment designs to suit particular well and reservoir conditions.
Early fracture-stimulation treatment designs used oil-based and water-based titanate/zirconate-crosslinked fracture fluids systems with mixed results. The most recent fracture stimulation treatments have employed a combination of a low polymer loading water-based borate-crosslinked fluid, and a Surface Modification Agent (SMA) to the proppant. The SMA increases the fracture conductivity, creates a flexible, stable proppant pack, reduces fines migration and fines invasion of fracture pack, assists in proppant flow back control; and reduces fracture cleanup time.
Sixteen wells were completed in the Clastic formation in late 1999 and early 2000. This paper discuss the design details and explains the changes made to the hydraulic fracture stimulation treatments to make this formation an economic success.
A Knowledge-Based System for Optimal Economic Design of Improved Recovery Processes
Authors: Gharbi R. B. C. 
Published: December 2007

Abstract
The main challenge of Enhanced Oil Recovery (EOR) processes at the prevailing low oil prices is to reduce the cost. An optimization methodology, combined with an economic model, is implemented into an expert system for optimizing the net present value of full field development with an EOR process. The approach is automated and combines an economic package and existing numerical reservoir simulators to optimize the design of a selected EOR process using sensitivity analysis. The EOR expert system includes three stages of consultations: (1) select an appropriate EOR process on the basis of the reservoir characteristics, (2) prepare appropriate input data sets to design the selected EOR process using existing numerical simulators, and (3) apply the discounted-cash-flow methods to the optimization of the selected EOR process to find out under what conditions at current oil prices this EOR process might be profitable. The project profitability measures were used as the decision-making variables in an iterative approach to optimize the design of the EOR process. The economic analysis is based on the estimated recovery, residual oil in-place, oil price, and operating costs. Two case studies are presented for two reservoirs that have already been produced to their economic limits and are potential candidates for surfactant/polymer flooding, and carbon-dioxide flooding, respectively, or otherwise subject to abandonment. The effect of several design parameters on the project profitability of these EOR processes was investigated.
A Novel Technique to Treat Asphaltene Deposition in Carbonate Rocks
Authors: Zekri Abdulrazag Y. , Almehaideb Reyadh A. 
Published: December 2007

Abstract
In this project, steam was tested to stimulate damaged limestone cores. Several dynamic experiments were conducted to determine the effect of asphaltene on the permeability of limestone cores. Plugging effects due to asphaltene deposition were evaluated through comparison with reference permeability measured prior to and after oil flow. Damaged cores were then subjected to steam soak process. The permeability of the cores was measured after each treatment. Core impairment resulting from in-situ asphaltene deposition, was found to cause a 56 to 89% loss of initial oil permeability depending on rock permeability and injection rate. Core stimulation resulting from steam soak treatment, was found to cause 24 to 230% improvement on the damaged core permeability depending on rock permeability. On average, 95% improvement in damged core permeability was obtained.
Experimental Investigation of the Feasibility of Steam/Chemical Steam Flooding Processes through Horizontal Wells
Authors: El-Abbas Abbas A. , Shedid Shedid A. 
Published: December 2007

Abstract
Laboratory studies and field applications have strongly established steam flooding as a valuable and remarkable recovery technique for both vertical and horizontal wells. This experimental study presents an investigation of the potential of enhancing tertiary oil recovery of heavy crude oil using steam, caustic steam, surfactant steam, and caustic-surfactant steam flooding through horizontal wells. The oil recovery of each process is measured and a comparison is carried out. The experiments were conducted using a box-shaped sandpack equipped with a centered horizontal well. The followed experimental procedure used the configuration of a horizontal steam injector with a vertical producer. The results of the dynamic experiments indicated that steam flooding through a horizontal well substantially improved oil recovery. Addition of caustic (sodium hydroxide) or surfactant (X-Triton-100) to steam drive recovered additional oil of 2.7 % IOIP or 5.6 % OOIP, respectively, than conventional steam flooding for water flooded reservoirs through horizontal well. In addition, the use of mixed solution of caustic and surfactant into steam current potentially enhanced oil recovery by almost 7.5 % IOIP than conventional steam flooding through horizontal wells for water flooded reservoirs. The above results indicate that steam and/or suggested chemical steam techniques are efficient methods for recovering heavy oil from water-flooded reservoirs. Key Words: Thermal methods, Chemical methods, Horizontal wells, and Fluid flow.
Development of Non Petroleum Base Chemicals for Improving Oil Recovery in Indonesia
Authors: Suryo Purwono , Murachman Bardi 
Published: December 2007

Abstract
The advantages of oil as primary energy source are still unsurpassed by any other source. After primary and secondary recovery, approximately 50 % to 70 % original oil in-place were left in reservoirs. The oil left is unrecoverable by conventional means. The enhanced oil recovery or tertiary oil recovery indeed is a very promising effort in the future. The goal of this research is to develop chemicals produced from local materials which can be used to optimize recovery and minimize residual oil in the reservoir by: lowering the oil / water interfacial tension and improving mobility ratio. A laboratory experiment had been carried out to simulate the process. The porous media used in the oil displacement process was prepared from stainless steel cylinder and contain fine crushed core. It is proposed to be an artificial reservoir with dimension about 3.75 cm ID x 10.8 cm L. The procedure of operation is as follows: initially the reservoir model was filled with brine until 100 % saturation. Then oil was injected into the medium to represent oil migration until water saturation become minimum (Swc), which is about 30 %. After this, the reservoir was flooded by the same brine until Sor was reached, which is about 10 %. The oil remaining in the reservoir after this water flood was then subjected to various injection of different chemicals for further oil recoveries. The experimental results show that some chemicals developed in the laboratory can be used as EOR chemicals. The oil displacement experiments show that as much as 20 % to 80 % of remaining oil can be recovered by flooding it with the chemicals. The results also show that the oil recovery depends on type of chemicals, chemical concentration, pressure and temperature, type of crude oil and the brine concentration.
Characterization of the Plus Fraction and Prediction of the Dewpoint Pressure for Gas Condensate Reservoirs
Authors: Elsharkawy Adel M. 
Published: December 2007

Abstract
This paper presents a new empirical model to estimate the dewpoint pressures for gas condensate reservoirs as a function of routinely measured gas analysis and reservoir temperature. The proposed model was developed using experimentally measured and collected data of 340 gas condensate samples covering wide rage of gas properties and reservoir temperature. The new model has an average relative deviation of 0.44 % and average absolute of 7.68% or 346 psia. The accuracy of the model has been compared to SRK-EOS, PR-EOS, and other correlations. The model proved to be superior for most of the gas condensate samples used in this study. Gas condensate samples from this study as well as from literature have been used to check the validity of the proposed model against EOS simulation. These examples have shown that the model successfully captures the physical trend and that the model is reliable. This model is useful to provide an estimate of the dewpoint pressure when experimentally measured ones is not available.
The current study also shows that predicting the dewpoint pressure for gas condensates depends on the EOS(s), the number of pseudo-components, and the characterization of the plus fraction. For most of the gas condensate used in this study, a ten to twelve pseudo-component of the heptane plus fraction resulted in minimum error in calculation of dewpoint pressures using PR-EOS with Pedersen characterization of the plus fraction.
Neural-Network Approach To Predict Well Performance Using Available Field Data
Authors: He Zhong , Yang Linyu , Yen John , Wu Ching 
Published: December 2007

AbstractAccurate prediction of future well performance is of great importance for petroleum reservoir management. This paper presents a practical neural network approach to predict existing and infill oil well performance using available filed data, such as well production history and well configuration information. It serves as a practical, cost-effective and robust tool for oilfield production and management. Well production, well spacing and the time-dependent information are used to train the neural network. The time-dependent information of wells are incorporated in a manner of time series for establishment of neural network. After the neural network is established, it is used to predict future performance of existing and infill wells. No reservoir data is currently used in the establishment of neural network, therefore it can predict well production performance in absence of reservoir data. Primary production of two data sets (each has 9 wells) in North Robertson Unit located in west Texas was tested using this approach. The results demonstrate that this approach is powerful in rapid projection of existing wells’ future performance, as well as the performance prediction of infill drilling wells.
Advanced Well Simulation in a Multilayered Reservoir
Authors: Verga F. M. , Griffa G. L. , Aldegheri A. 
Published: December 2007

Abstract
In the past years technological advances in drilling and completion have provided the possibility of improving the reservoir productivity by resorting to new options such as multilateral wells and intelligent completions or a combination of both. However, some serious difficulties arise to simulate the performance of advanced wells as standard well models neglect friction effects along deviated drains and do not allow selective fluid flow control when bottom hole flow control devices are used.
Some new simulation options have been recently developed that, reportedly, provide a thorough description of the local flowing conditions along the well and account for pressure losses along the wellbore and across any flow control device. The new simulation options were applied to simulate the performance of a dual opposed, stacked lateral well completed with bottom hole flow control devices draining an oil reservoir comprising two hydraulically separated pools. During the first years of production the two drains were initially left open hole. When water break through occurred and water production started to progressively increase, the possibility of adopting an intelligent completion to control fluid entry from each drain appeared very attractive to optimise oil production. Therefore, a 3D numerical model of the reservoir was set up. Once the calibration of the model was attained, the use of intelligent completions was simulated in an attempt to evaluate the reservoir performance when flow control was applied to each drain, and to determine the optimal well configuration to maximise productivity. Productivity forecast showed that intelligent systems allow both enhancement of oil production and dramatic reduction of water production compared to the case where conventional completions are adopted.
Modeling and Simulation of the Wafer Non-Darcy Flow Experiments
Authors: Li Dacun , Svec Robert K. , Engler Tom W. , Grigg Reid B. 
Published: December 2007

Abstract
Darcy's law governs most flow patterns in petroleum recovery processes. However, when fluid flow velocity is very high, for example, near the wellbore, Darcy's law may be inadequate to simulate the fluid flow.
The non-Darcy effect has been incorporated into the Department of Energy (DOE) reservoir simulator MASTER (Miscible Applied Simulation Techniques for Energy Recovery). Based on the simulator BOAST (Black-Oil Applied Simulation Tool), MASTER was developed by DOE mainly to solve gas injection problems. However, only Darcy's flow was considered in these simulators. In this study, Forchheimer's non-Darcy flow equation has been incorporated into the simulator code and an iterative method has been used to solve for pressures.
The modeling of non-Darcy flow proved successful and enabled the simulator to match high-velocity gas flow more accurately. Based on a number of non-Darcy flow coefficient equations found in the literature, a general correlation was proposed. The appropriate constants in the proposed correlation were found by running simulations with the modified simulator for the non-Darcy flow experiments.
The model has been verified using laboratory high flow data obtained using single-phase nitrogen gas. The data comprised a wide range of flow rates collected using a heterogeneous Berea sandstone wafer. The gas flowed into and out of a hockey puck-shaped wafer via 0.125-in. diameter ports. Thus the flow rate varied within the wafer, simulating near-wellbore flow conditions. It was found that, the differential pressures from simulations were in good agreements with their counterparts from experiments.
Mapping of Permeability Structure in a Naturally Fractured Reservoir Using Field Performance Data
Authors: Anguiano Juan A. , Ershaghi Iraj , Christensen Karen I. 
Published: December 2007

Abstract
This paper presents the results of a detailed study examining the permeability characteristics of a naturally fractured reservoir using the performance data from individual wells. The study relates to naturally fractured reservoirs where the wells that intersect highly fractured and brecciated intervals are the most prolific producers. Substantial historical production history data on individual wells are examined using a type curve approach. The early production decline, from fracture-controlled period, is used to estimate equivalent permeability-thickness product for individual wells. The matching process is similar to the method suggested by Fetkovich1 for homogeneous reservoirs. Deviation from this model, attributed to a support system, is compared with two plausible systems. Because of the rapid onset of the deviation from the fracture controlled decline, high values of interporosity parameter are noted unmatched by observations from matrix petrophysical properties. The two systems compared are the dual-fracture model published by Al-Ghamdi and Ershaghi2, which is selected for its representation of network of microfractures as the main support system, and the dual porosity/permeability models which are the most commonly used models in commercial simulators to represent naturally fractured reservoirs.