bluuebunny/crossref_metadata_2025_split huggingface dataset:
Successful Results Achieved by Applying New Sandstone Acidizing System in the Burgan Field: A Case History
Authors: Chakraborty P. K. , Al-Haddad S. , Jamal I. , Gizi N. H. 
Published: December 2007

Abstract
The Greater Burgan Field, located in southeastern Kuwait, covers about 320 sq miles of surface area and is classified as the largest clastic oil field in the world. The field produces mainly from cretaceous age sandstones of the Burgan, consisting of Third, Fourth and Wara formations.
The field was discovered on February 23, 1938, and production began eight years later. The Burgan formation holds most of the hydrocarbon reserves and accounts for approximately 90% of the field production.
Sandstone acidization offers major challenges to the petroleum industry, and previous treatments in this field did not reveal encouraging results. The application of recently introduced advanced fluids and engineering designs for sandstone acidizing has shown successful results. In addition to choosing the correct fluid system for the main acid treatment to avoid secondary precipitations, considerations for choice of appropriate type and correct volume of preflushes to condition the formation and use of proper overflushes proved essential.
This paper describes the application of a new sandstone acidizing system applied to a well completed in the Third Upper sandstone. This well had ceased to flow due to formation damage and was shut in for a long time. Core samples and reservoir rock properties were used to customize the acid system. The understanding of reservoir rock properties and the systematic approach of treatment design were key factors in employing this system. The system was tailored to penetrate deep into the formation while removing near wellbore damage.
Post-job production showed a significant gain from 0 to 949 BOPD of dry oil. To date, production has been sustained more than four years, adding value by saving the cost of repeated acid stimulation jobs and also by adding to the value of additional incremental oil gains.
The post-job analysis of results enabled further optimization of these processes, which would facilitate similar applications in many more wells in the region.
Using Integrated Project Models to Evaluate Field Development Options
Authors: Bilderbeck M. G. , Beck I. V. 
Published: December 2007

Abstract
This paper presents a practical and effective development concept evaluation and screening methodology that recognizes the fundamental relationship between reservoir potential and field development strategy.
A spreadsheet-based project modelling environment that integrates reservoir models and a field development planning model is described. The reservoir models account for uncertainty in reservoir performance. The field development planning model handles the scheduling and costing of wells and processing facilities. The use of uncertainty-based projections of reservoir performance to drive well and facility construction plans is illustrated.
The relative merits of adopting a multi-phase approach to the construction of facilities (to enable the opportunity to learn about a reservoir as a project matures), as opposed to a single-phase, up-front construction of facilities (to capture economies of scale), is discussed.
Lastly, the relative impact of uncertainty in the unit cost of wells and facilities, due to fluctuations in market demand for oilfield services, is examined.
To illustrate the benefits of this project modelling methodology, an example of its use is presented. The example consists of a large Middle East field in which further development is being considered, to increase production.
Live Oils Novel Organic Solid Deposition and Control Device: Wax Deposition Validation
Authors: Zougari M. , Hammami A. , Broze G. , Fuex N. 
Published: December 2007

Abstract
A novel laboratory-scale flow assurance tool termed "Organic Solids Deposition and Control (OSDC)" device has been developed to assess the potential and severity of organic solids deposition problems from hydrocarbon fluids at realistic production and/or transportation conditions. Based on optimized Taylor-Couette flow in concentric cylinder geometry, the OSDC mimics production conditions of temperature, pressure, composition, turbulence, shear, surface type and roughness.These key parameters can be accurately and independently controlled, allowing the deposition tests to be conducted over a wide range of conditions. Uniquely, this new device can simulate production system thermal-hydraulic conditions and produce fully developed turbulent flow for the live fluids and stock tank oils investigated.Heat transfer and fluid dynamics in the device were characterized through careful and detailed experimentation.Deposition tests performed on small volumes of live waxy crude oils resulted in the generation of reproducible wax deposits under consistent test conditions. The wax deposition rates were comparable to those from pilot-scale flow loops that utilized larger volume of fluid.
Review and Application of Short-Term Pressure Transient Testing of Wells
Authors: Soliman M. Y. , Azari M. , Ansah J. , Kabir C. S. 
Published: December 2007

Abstract
Short-term pressure transient testing is gaining increased acceptance as an attractive alternative to conventional transient well testing, since the latter usually requires long flow and shut-in periods in order to meet test objectives. Unfortunately, current industry drivers are focusing on short, cost-effective, and environmentally friendly test procedures _ especially in exploration wells in deepwater and arctic environments where conventional tests may be prohibitively expensive or not feasible logistically.
While various short-term tests, test procedures, and interpretation methods are available for conducting successful short-term tests, clarity is lacking for specific applications of these methods. Some of these tests include surge testing, closed-chamber testing, slug testing, underbalanced perforating and testing, and back-surge perforation cleaning. This paper provides comprehensive evaluation of general closed-chamber tests, including general surge tests, and their comparison with special tests such as, FasTest,™ Impulse™ test, and slug tests. For each of these techniques, the review will examine: Test design, testing procedureTheoretical background of each of these techniquesMethod of data analysis including comparisons based on both theoretical and practical considerations to determine the expected reliability, accuracy, and ease of analysis.
A large portion of the paper is devoted to field examples. Several field cases are analyzed using the various techniques, and results are tabulated and presented. Analyses of these examples are presented in significantly more detail to compare the many techniques available to analyze the well-testing data obtained from surge testing, closed-chamber DST, slug testing of oil wells, underbalanced perforating and testing, and back-surge perforation cleaning.
An Integrated RRT Prediction Method Combining Thin Sections, Sequence Stratigraphy and Logs
Authors: Chautru J. M. , Arab H. , Fujita N. , Pluchery E. , Poli E. , Shebl H. , El-Henshiri M. Y. , Shikama T. 
Published: December 2007

Abstract
This paper presents an integrated rock-typing workflow leading to enhanced 3D static models. The work is based on the integration of several tools which optimize the contribution of all the available data :
a specific thin-section description methodology sophisticated log-derived electrofacies calibration approaches, incorporating sequence stratigraphy rules; an enhanced calibration approach based on dynamic data.
It is illustrated by an application to the lower cretaceous carbonate reservoir in offshore Abu Dhabi.
The different steps of the methodology and their mutual interaction are detailed. This integrated work establishes a consistent way to fill the gap between core and production scales, using log-derived electrofacies extendable to all the logged wells. It is shown first how sequence stratigraphy can provide a global framework, common to the different scales that ensure the consistency of the whole work. Then, emphasis is put on the sophisticated thin-section description methodology, based on facies association identification and sequence stratigraphy, which facilitates the further electrofacies calibration. In a third step, we detail the log-derived electrofacies determination and calibration methodology, which takes into account thin-section description, core descriptions, sequence stratigraphy analysis, CCAL data, and SCAL data in order to provide consistent rock-types in uncored wells. In the end, it is shown how the integration of dynamic data in a well by well QC can significantly enhance the prediction of high permeability drains.
Modeling issues are then discussed, focus being put on the relationship between the various scales, on the geological control and robustness of the final 3D model that are enhanced by the large number of control points provided by the extension of rock-types to non-cored wells. The impact on dynamic modeling is shown as a conclusion.
On The Adjoint of a Nonlinear Diffusion-Convection Equation to Describe Flow in Porous Media
Authors: Vakili A. , Jansen J. D. , Esmaiel T. , Van Kruijsdijk C. P. J. W. 
Published: December 2007

AbstractIn this study Optimal Control Theory (OCT) was used to formulate the adjoint equation of a one-dimensional horizontal two-phase flow reservoir described by linear and nonlinear Diffusion-Convection Equations (DCEs). The use of tuning parameters allowed for a gradual transition between the linear and the nonlinear equations to determine the effect of nonlinearities on the solution of the adjoint equation. A numerical adjoint formulation was obtained from explicit and implicit finite difference discretizations of the linear and the nonlinear DCEs. A semi-analytical solution was obtained for the continuous adjoint of the linear DCE which served as a reference for analysis of some of the numerical results. Based on a simple example we found that for the linear model numerical dispersion did not affect the stability of the adjoint equation and that the resulting gradients remained stable. Explicit numerical implementation of the nonlinearities in the capillary pressure and fractional flow functions resulted in non-smooth (mildly oscillating) gradients of the objective function with respect to the controls for a number of time steps. A matrix stability analysis revealed the occasional occurrence of eigenvalues with magnitude one, indicating marginal stability, but no true instabilities were encountered. The observed oscillations in the gradients are not desirable for optimization purposes, since the resulting injection rates are fluctuating and the convergence of the optimization algorithm becomes difficult. However, the gradients became smoother for smaller time step sizes which suggests the need to use a smaller time step size for solving the adjoint equation than for solving the forward model.
Electrical Submersible Progressive Cavity Pump (ESPCP) Application in Kulin Horizontal Wells
Authors: Taufan M. , Adriansyah R. , Satriana D. 
Published: December 2007

Abstract
The original Kulin Horizontal well project scope was to drill two horizontal wells and run Electric Submersible Progressive Cavity Pumps (ESPCP's). ESPCP is a combination of Progressive Cavity Pump (PCP) and Electric Submersible Pump (ESP) motor as a down hole fluid lifting system and is ideal for use in horizontal wells. With rod less system, it will eliminate friction loss at tubing and rod. The PCP has more resistance to sand production and provides high efficiency production of viscous fluid. The Kulin Horizontal Drilling project started in early 2002 and ended in February 2003. The first horizontal well was Kulin 082 (KL082) and the second well was Kulin 083 (KL083). After the wells were completed using ESPCP as artificial lift, the initial production for KL082 was 708 BFPD, 531 BOPD, 25% water cut and KL083 was 518 BFPD, 394 BOPD, 24% water cut. The initial production was above estimated initial production of 300 BOPD/well.
The ESPCP's in both Kulin horizontal wells are installed in tangent sections with less than 2 °/100 ft build rate inside 9-5/8" production casing. The design threshold for ESPCPs is up to a maximum of 15°/100 ft build rate in the tangent section. The stator elastomer inside the PCP is operated at temperatures between 135°F and 150 °F and this is below the maximum temperature limitation for the elastomer. The flow rates, head and pump efficiency of the ESPCPs are controlled using surface mounted Variable Speed Drive (VSD).
As of June 2004, the ESPCPs that are installed in both Kulin horizontal wells have been operating for over 450 days and 800 days respectively without any mechanical problem from pump or ESP failures. Both ESPCPs was down in period mid of June’04 until early August’04 when the Kulin field was shut down due to facility safety issue.
The production rates from these horizontal wells are about 2.5–3.5 times greater than an average vertical producer in the field.
This paper will discuss ESPCP design, installation and performance in the Kulin Horizontal wells.
Minas Gas Compression and Liquid Handling Optimization Project
Authors: Ihwanto T. , Putra E. , Uditoyo S. 
Published: December 2007

Abstract
The gas compressor optimization project was established in late 2002. This project focused on gas processing and liquid handling to ensure reliable gas compressor operation and to secure condensate production. A cross-functional team was formed to perform comprehensive efforts to improve facility performance in dealing with field dynamic and to develop required action plans.
Since then, gas compressor unit reliability improves from 92 % in 2001 to 97 % in 2004. The improvement translates into flare rate reduction and operational cost savings. In the same time, condensate production shows improvement in term of quantity and quality. While sustaining the ongoing efforts, team presently works on look back to review results, lesson learnt and to identify new opportunities. This paper will describe the utilization of asset management process and executed efforts.
Production Optimization in ESP Completions Using Basic Intelligent-Well Technology
Authors: Vachon G. , Bussear T. 
Published: December 2007

Abstract
Of the various mechanisms that currently enable intelligent well systems, open/close remote-controlled sleeves and strain gauges are mature and less expensive than chokes and quartz gauges, yet they have many interesting applications when used in combination with Electric Submersible Pumps (ESPs). Though limited in functionality, they enable applications such as selective isolation of zones, as in the case of anticipated water breakthrough; fluid loss prevention when the ESP is turned off; or tandem ESP configurations for pump boost or redundancy. The lower costs of these tools make them economically attractive in many artificially lifted wells.
Impact of Off-Balance Fracturing on Borehole Stability and Casing Failure
Authors: Daneshy A. A. 
Published: December 2007

Abstract
Creation and presence of the hydraulic fracture can cause casing failure both during and after the fracturing operations. Although such failures are known to occur and have been a concern to many operators, the petroleum industry literature contains very little information on the subject.
During the fracturing operations, casing can fail under tension across the fractured interval either by de-threading of the collars or by tensile failure at perforations. The three main factors contributing to this failure are thermal shrinkage of the casing, off-balance fracture growth, and pseudo-openhole environment. Other contributing factors are borehole inclination with respect to the fracture plane, and the quality of the cement bond.
Factors contributing to casing failure during well production include changes in in-situ stresses due to reduction in reservoir pressure, off-balance fracture growth, formation layering and its inclination with respect to the wellbore, and shear strength of the interfaces. In particular, off-balance growth may create fractures that are not symmetrical with respect to the wellbore, and have different lengths in different layers. The resulting differential reservoir compaction induces shear stresses along the interfaces which can cause casing failure along the weakest interface.
The low formation shear strength along the propped fracture plane increases the probability of shear movement along it. Presence of the fracture will direct this movement towards the casing and can cause its shear failure. Rapid production pressure declines increase the shear stresses acting on the fracture plane and can cause movement along the fracture plane and casing failure.
Enhanced Oil Recovery in East Texas
Authors: Hyatt J. H. , Hutchison D. A. 
Published: December 2007

Abstract
This paper describes a working gas injection pilot that is demonstrating additional oil recovery from a very mature field.This small, low cost pilot has been very valuable in understanding and demonstrating commercial viability of this enhanced oil recovery (EOR) process before larger scale implementation.After nearly 70 years of water drive production, this immiscible gas injection process has enabled conversion from viscous displacement water drive to gravity stable, film drainage behind an advancing gas front.The design, implementation and current pilot results are discussed as well as the role of three dimensional (3-D) geocellular and flow simulation models.Current full-field implementation project design efforts based on pilot performance and learnings are also described.
Artificial Neural Network Model for Predicting Bottomhole Flowing Pressure in Vertical Multiphase Flow
Authors: Osman E. A. , Ayoub M. A. , Aggour M. A. 
Published: December 2007

AbstractAccurate prediction of pressure drop in vertical multiphase flow is needed for effective design of tubing and optimum production strategies.Several correlations and mechanistic models have been developed since 1950.In addition to the limitations on the applicability of all existing correlations, they all fails to provide the desired accuracy of pressure drop predictions.The recently developed mechanistic models provided little improvements in pressure drop prediction over the empirical correlations.However, there is still a need to further improve the accuracy of prediction for a more effective and economical design of wells and better optimization of production operations.This paper presents an Artificial Neural Network (ANN) model for prediction of the bottom-hole flowing pressure and consequently the pressure drop in vertical multiphase flow.The model was developed and tested using field data covering a wide range of variables.A total of 206 field data sets collected from Middle East fields; were used to develop the ANN model. These data sets were divided into training, cross validation and testing sets in the ratio of 3:1:1. The testing subset of data, which were not seen by the ANN model during the training phase, was used to test the prediction accuracy of the model and compare its performance against existing correlations and mechanistic models.The results showed that the present model significantly outperforms all existing methods and provides predictions with higher accuracy.This was verified in terms of highest correlation coefficient, lowest average absolute percent error, lowest standard deviation, lowest maximum error, and lowest root mean square error.A trend analysis was also conducted and showed that the present model provides the expected effects of the various physical parameters on pressure drop.
Spontaneous Imbibition Studies of Australian Reservoir Rocks With Neutron Radiography
Authors: Middleton M. F. , Murdoch U. , Li K. , de Beer F. 
Published: December 2007

Abstract
Spontaneous imbibition experiments were carried out on three core samples from the Mardie Greensand and one core sample of Barrow Group sandstone from the Australian North West Shelf. Water uptake into the samples, which were initially air-saturated, was measured by dynamic neutron radiography. The observed data were interpreted by (1) the linear diffusion-equation approximation for fluid flow and (2) the Li and Horne model. Both these models were consistent with the observed data, and have similar consequences. The linear diffusion-equation model suggests that a constant diffusion parameter, Dw, can adequately describe the observed spontaneous imbibition of water into these samples, under ambient temperature and pressure, throughout most of the imbibition process. The Li and Horne model suggests that (1) the effective water permeability of the sample and (2) water permeability times the capillary pressure gradient within the sample are approximately constant through most of the imbibition process, during these experiments. The combined conclusion of these interpretational methods implies that the water permeability and the capillary pressure-water saturation gradient in these samples are constant throughout most of the imbibition process, under ambient temperature and pressure conditions.
Dynamic Underbalanced Perforating on a Mature North Sea Field
Authors: Martin A. J. , Clark D. , Stirton G. 
Published: December 2007

AbstractDynamic underbalanced perforating1 is a technique for obtaining clean perforation tunnels resulting in much improved production or water injection. This technique has been successfully applied to several wells in the Ninian Field in the UK sector of the North Sea, resulting not only in better wells, but also in increased completion efficiency. In August 2003 a closed-chamber, dynamic underbalance shoot and pull operation was performed on Ninian North—a world first. The well came in at 50% higher production than expected. Since then, several other wells have been perforated using the same technique. Gauge data on the early wells showed the sequence of events, but did not capture the detail. A more recent well has been perforated using a new high-speed gauge that revealed the extent of dynamic underbalanced achieved. This paper describes the method, shows the results and discusses the value of using this technique.
Follow-Up Planning Tool for Material Planning, Delivery Management, and Stock Control in Well-Connection Material
Authors: Manuhoro P. 
Published: December 2007

Abstract
Total E&P Indonesie is one of the leading gas producers in Indonesia supplying more than 65% of the gas liquefied at the Bontang liquefaction plant. Operating 8 drilling rigs in all of their concession area, they drill an average of 150 wells within three years. This aggressive drilling activity is done to meet the natural gas delivery contract.