bluuebunny/crossref_metadata_2025_split huggingface dataset:
A Laboratory Investigation of the Effectiveness of Steamflood Additives in Recovering Viscous Heavy Oil
Authors: Sarma H. K. , Ohno K. , Nakamura S. , Horikawa H. 
Published: December 2007

Abstract
This paper presents a laboratory investigation of the effectiveness of steamflood additives in recovering a viscous heavy oil. The test oil was obtained from the Ikiztepe field, Turkey (API gravity = 9° and a measured oil viscosity = 4190 mPa.s @50°C). All displacement tests were conducted in Berea sandstone cores in a controlled environment. The additives evaluated were: hexane, petroleum benzine and condensate, and the displacement tests were conducted in the following three categories: (i) base-line conventional steamfloods, (ii) steamfloods with each of the three additives, and (iii) conventional steamfloods for a given length of time followed by steamfloods with each of the three additives. Also, three additional steamfloods with varying condensate concentrations as the additive were conducted to investigate the effects of the concentration on the oil recovery, and to determine if there existed an optimum additive concentration.
For each test, the incremental oil recovery due to the additive has been estimated, and compared with the recovery obtained in the base-line conventional steamflood. In all cases, steamfloods with the additive proved superior to the conventional steamflood (i.e., without additives) in enhancing the recovery of the oil. However, results also suggest the existence of an additive concentration at which the recovery is optimum; that is, the effective benefits of increasing the additive concentration become less pronounced above such optimum concentration both in terms of the cost and additive-utilization factor. A simple cost-effectiveness analysis is also provided based on the additive cost. Finally, the experimental data are matched using a thermal simulator, and a sensitivity study is carried out to identify the more important process parameters, and to evaluate naphtha as another potential additive.
Implementation of Reservoir Management Plan - Self Unit, Glenn Pool Field
Authors: Kelkar Mohan , Richmond Dan 
Published: December 2007

Abstract
This project used an integrated approach to improve the water flooding performance of a mature oil field producing over a 90 year period. Even after 90 years of production, only 21 % of original oil in place has been produced. Further, the past history of the field indicates that the field has responded well to different changes in the production strategy. We used geological, geophysical and engineering data to develop a detailed reservoir description. Based on flow simulation studies, we observed that the best strategy to improve the recovery from this unit is to selectively perforate part of the interval and increase the water injection rate.
We have started implementing the reservoir management plan in the field. Seven wells are selectively perforated and completed. The oil production has increased by about 35 bbls/day. We expect that after completion of the implementation, the production will go up by a total of 55 to 75 bbls/day. The economic evaluation indicates that the finding cost of oil is in the range of $ 4.50 to $ 6 per barrel.
The technologies used in our project are cross bore hole tomography, formation micro-resistivity bore hole imaging, geological description based on genetic units, geostatistics, and field flow simulation. We believe that with the exception of cross bore hole tomography, all the other techniques were very helpful in improving the reservoir description.
Effect of Reservoir Connectivity on Primary and Secondary Recovery
Authors: Pawar R. J. , Deo M. D. , Dyer J. E. 
Published: December 2007

Abstract
An earlier reservoir simulation study of the successful water flood application in the Monument Butte Unit (MBU) (Green River Formation, Uinta Basin, Utah) revealed that the primary production and secondary recovery from the unit were affected by the fluvial deltaic nature of the reservoir. The two primary sands in the unit, the D and the B extended well beyond unit boundaries. Geostatistical conditional simulations were performed on a 12-section area around the MBU to assess reservoir connectivity in the region. Reservoir simulations were performed using the resulting geostatistical images. Representing the unit sand bodies on a larger scale did not have a significant impact on production from the unit because of the overall permeability structure in the reservoir.
Building Geostatistical Models Constrained by Dynamic Data - A Posteriori Constraints
Authors: Blanc G. , Guerillot D. , Rahon D. , Roggero F. 
Published: December 2007

Abstract
This paper describes one solution to the problem of constraining geostatistical models by well-test results which has been obtained within the frame of the HELIOS research project conduced by Elf and IFP in the field of reservoir engineering.
To do so, a numerical simulation program devoted to the simulation of well-tests has been coupled with a nonlinear constrained optimization program to make an inversion loop. The resulting software package provides the reservoir engineer with a tool to compute the set of optimal facies or rock-type properties and the well skin which give the best fit between the simulated and the measured well pressure during the test duration. Any petrophysical facies or rock-type property can be assigned either a constant value everywhere or a Gaussian distribution defined by its mean and its standard deviation.
On one hand the numerical program is able to compute not only the pressure and its derivative but also the gradients of this pressure with respect to the petrophysical facies or rock-type properties and with respect to the well skin. The gradients used by the optimization program to control the search algorithm can also be used as a stand alone diagnosis tool to analyze the simulation results.
Several examples are given which show the efficiency of the various algorithms. These examples also demonstrate the wide range of applicability of the software package to analyze and to interpret well-tests as well as to integrate dynamic data in geostatistical modeling.
As a conclusion, the paper sets forth several new research axes to extend this work toward the inversion of the shape of the geostatistical images themselves.
Capillary Limit Effective Two-Phase Properties for 3D Media
Authors: Ekrann S. , Dale M. , Langaas K. , Mykkeltveit J. 
Published: December 2007

Abstract
The paper describes an approximate method to compute effective relative permeabilities and capillary pressure for 3D heterogeneous porous media. The method is based on the self-consistent approximation, and works in the capillary (quasi-static, low velocity) limit.
The method needs as input data for the individual rock types making up the heterogeneous medium, their relative occurrence, and information related to the ratio between vertical and horizontal length scales of the heterogeneities. No actual realization of the heterogeneous medium is needed. The method is computationally very efficient.
Example effective properties are given, demonstrating capillary trapping, and the tensorial nature of effective relative permeabilities.
The accuracy of the self-consistent approximation is known to be quite satisfactory for most heterogeneity types.
We have also studied the applicability of the capillary limit, using numerical simulation. At typical reservoir rates, the capillary limit appears to be valid only for heterogeneities at the sub-meter scale.
Well Placement Optimisation and Risking using 3-D Stochastic Reservoir Modelling Techniques
Authors: Seifert D. , Lewis J.J.M. , Hern C.Y. , Steel N.C.T. 
Published: December 2007

Abstract
The cost-effective development of small fields requires a thorough description and evaluation of the reservoir, with a strong focus on the estimation of associated uncertainty. This paper describes a new, integrated methodology for defining and risking optimum high-angle development wells as applied to a UKSNS basin-margin gas reservoir. Sequential Indicator Simulation (SIS) realisations of genetic unit distributions were generated for each target reservoir zone, conditioned with relevant geological data derived from the reservoir and the analogue outcrop. The models were "pin-cushioned" with a large variety of well trajectories that varied in terms of inclination, azimuth, length and position within the zone. Genetic unit strings are then extracted from each well trajectory and analysed statistically, resulting in ranked well trajectories. This integrated approach produces ranked and risked well planning options, on which risk-conscious management decisions are readily made.
Introduction
Development decisions are increasingly taken with less data, and the use of minimal facilities requires that optimisation of development wells is more critical than formerly. The planning of development wells in complex reservoir sequences necessitates the detailed integration of data to rank potential well locations and trajectories. Utilisation of hybrid deterministic-stochastic reservoir models, enables this process to be carried out efficiently, with quantification of associated risk. The benefit of optimising the placement of high angle wells is that the risk associated with well placement is minimised and that the maximum volume of the reservoir can be accessed with the least number of wells, which in turn is highly cost effective.
The methodology of this study is outlined in Fig. 1. Detailed quantification of the controls on well performance within the reservoir was followed by the definition of the appropriate genetic units. In parallel, a period of sourcing and appraisal of possible outcrop analogues was followed by a detailed outcrop study which resulted in the derivation of quantitative data of the analogue with relevance to the Frobisher reservoir. Integration of the reservoir specific and outcrop analogue data into a hybrid deterministic-stochastic model provided the basis for determination of the optimum well trajectories and subsequent risking of their success in penetrating pay.
This paper will only briefly introduce the geological analyses of the reservoir and the outcrop analogue but will focus in detail on the generation of the reservoir model and on the determination and risking of the optimum well trajectories.
Relative Permeability Characteristics of Vugular Cores - Their Measurement and Significance
Authors: Ehrlich Robert 
Published: December 2007

Abstract
Carbonate reservoir rock can have a highly developed secondary fracture/vug network in addition to intergranular porosity. Because of this, the multiple phase flow properties are very much different from rocks with wholly intergranular porosity. This paper represents an attempt to characterize the immiscible displacement behavior of fractured and vugular reservoir rock.
An apparatus and method for the determination of relative permeabilities in large vugular cores is presented. The errors associated with this method and with vugular core analysis in general are discussed. To test the significance of relative permeability and other data obtained from core measurements, a mathematical model is proposed for the secondary pore network. This model permits the simulation pore network. This model permits the simulation of cores of unlimited size to predict realistic reservoir flow properties.
It is concluded that water and gas reservoir displacement efficiencies will be underestimated using core measurements where a substantial secondary pore system exists.

Introduction
Dolomitized limestone reservoirs can have a highly developed secondary network of fractures and vugs in addition to a primary (intergranular) pore system. Reservoirs with secondary pore pore system. Reservoirs with secondary pore systems are highly productive and have flow properties quite different from those with wholly properties quite different from those with wholly intergranular porosity.
This paper represents the beginning of an attempt to characterize the relative permeability and immiscible displacement behavior of fractured and vugular reservoir rocks. It is concerned specifically with reservoirs in the Acheson-Homeglen-Rimbey D-3 Reef Trend in Western Canada, but should be at least qualitatively applicable to similar formations.
The D-3 formation is a series of bioherm reefs whose primary biological structure has been obliterated by dissolution and dolomitization processes. The rock contains vugs of various processes. The rock contains vugs of various sizes interconnected by minute shrinkage cracks. There are also larger fractures of mechanical origin. The permeability of the formation ranges from about 100 md to about 3000 md2. The primary porosity is very tight, with only about 0.01 md to porosity is very tight, with only about 0.01 md to 0.1 md permeability.
The Resurgence of ECP's at Prudhoe Bay/North Slope
Authors: Gai H. , Walz G. , Nakamura D. , Burnham M. 
Published: December 2007

Abstract
This paper reviews historical and current ECP (External Casing Packer) applications by BP and ARCO in Alaska. The potential of the tool together with its reliability and effectiveness is critically evaluated. The "success rate" so far has been variable but it is believed that the reasons for this have not been properly investigated and understood up to now. Problems (related to equipment, procedures, job design, and so on) which caused various failures have been identified and analysed in detail. Case studies are presented to demonstrate why some failures occur and how they could be avoided. Procedures and proposals to combat the identified problems are recommended.
Because the associated application environment and problems are better understood and the lessons learnt are better communicated, and ECP technology is being renewed at a pace not seen before, it is believed that the ECP is a viable completion tool if used properly.

Introduction
To obtain a better understanding of ECP's performance and to improve their effectiveness for the increasing challenges in zonal isolation in horizontal and multilateral wells, a comprehensive internal study was carried out in 1994/5 within BP world-wide and ARCO Alaska and with the cooperation of some major ECP manufacturers. This paper concentrates on part of the results relating to ECP applications in Alaska.

Basics of ECP's and Setting Tool Operations
It is intended here to provide some basic principles which are necessary to understand the operations and the associated problems discussed later.
Principles of ECPs. ECPs or by other names such as CAPs (Casing Annulus Packer) or ACPs (Annulus Casing Packer), are made of a metal mandrel (a [pup] joint of casing) and an external elastomer tube bladder with an inflation valve system. This elastomer tube is always reinforced by typically metal ribs either continuously or only at the end sections. Both ends of the rubber tube are sealed and secured to the steel collars which have the nominal OD of the packer to protect the rubber element in the middle to a certain extent. Note conventionally the ECP is identified by the casing OD/weight/grade and the seal element length. The OD of the ECP has to be specified separately. One of the collar contains the valve system, which connects and controls the inflation fluid from inside the mandrel (the central hole) to the outside to expand and inflate the bladder and then shuts, all controlled by shear-pin-determined differential pressures.
The valves are shear-pinned to predetermined pressure values to control the function of the inflation port, depending on the differential pressure between the central hole and the annulus. There are typically 2 main valves: one to open (e.g. Lock Shut Valve "LSV" or Delay Open Valve "DOV") the inflation port and the other to close it (Inflation Control Valve "ICV") once the internal pressure has reached the pre-set level. There may be some minor check valves in the system. P. 83
Technique to Estimate Fluid-Loss and Fracture Geometry of Fracture Acidizing with Foamed/Non-Foamed Acid
Authors: Fagang Gu. , Shuquan Ren. , Ziguang Yuan. 
Published: December 2007

Abstract
A technique to estimate fluid-loss, hydraulic fracture geometry and acidized fracture geometry is developed for fracture acidizing with foamed or non-foamed acid on the basic of PKN fracture model1,2. The treatment processes are simulated during injecting and the practical bottom hole pressures after shut-in are matched with the predicted bottom hole pressures in this technique. The corresponding models to simulate fluid temperatures, pressures and flow in a fracture after shut-in are established and the models to calculate bottom hole pressures after shut-in from tested wellhead pressures while a foamed fluid is used as a overflush fluid are presented.
The study indicates the flow rate in fracture is a variable during injecting and continuous flow into fracture exists after shut-in because of thermal expansion and compressibility when foamed acid is adopt in treatments. The bottom hole pressures are overestimated without consideration of warming up and continuous flow. The comparison study of two wells shows that the fluid-loss is underestimated with not considering the thermal expansivity and compressibility of fluids, CO2 produced by acid-rock reaction and the heat of acid-rock reaction. The influence of thermal expansion is most significant in the two well investigations and is more pronounced in treatments with foamed acid.
High-Quality Foam Fracturing Fluids
Authors: Harris Phillip C. , Heath Stanley J. 
Published: December 2007

Abstract
A recent research project was conducted to determine whether a stable, fine-textured, 95% gas content foam could be made. The viscosities of 95-quality N2 foams were measured in a recirculating flow loop viscometer.
Only foam prepared from 2% of an anionic surfactant with plain water had uniform, fine-bubble structure (texture) at 95 quality. All other combinations of additives or other foamers (nonionic, amphoteric or anionic, and/or 0.24% guar) produced unstable foams at 95 quality and stable foams at lower quality.
Foams that were unstable at 95 quality typically contained large slugs of N2 gas within the foam structure. Unstable, high-quality foams did not invert phases to form a mist. Instead, such foams were mixtures of very small and very large bubbles. The net viscosity and stability of those fluid systems were lower than that of a uniform, fine-textured foam.
Yield points were measured for fine-textured foams at 70 to 95 quality. These new yield points were higher than yield points in earlier data.
Advanced Technologies for Producing Massively Stacked Lenticular Sands
Authors: Kuuskraa Vello A. , Prestridge Andrew L. , Hansen John T. 
Published: December 2007

Abstract
The massively stacked, lenticular sands of the Piceance, Green River, and Uinta basins have been judged, by the USGS, to be the largest undeveloped gas resource in the U.S. Past attempts to produce natural gas from these formations have been, in the main, disappointing. Six advances in technology offer potential for unlocking a portion of these gas resources and turning them into near-term, low cost gas reserves:–Natural fracture detection to find "sweet spots",–Advanced well log analysis to target productive pay,–Advanced well completion and stimulation to connect pay to the wellbore,–Intensive infill development for efficient drainage,–Recompletion of old wells to add reserves, and–Best practices to reduce costs.
Field case studies at Rulison Field, Piceance Basin show how each of these technologies have been applied. The package of technologies presented in this paper may help producers develop stacked, lenticular sands in other basins.
This assessment is part of a Gas Research Institute (GRI) research project examining technology improvements for lowering the costs of future gas supplies.

Introduction
Improved well siting and completion practices have revived a previously discovered, but commercially condemned tight gas play in the southern Piceance Basin of Colorado. Here, the target is the massively stacked, lenticular sands (and coals) of the Mesaverde Group, Williams Fork Formation stretching upward for several thousand feet from the top of the Rollins, through the Cameo coal and sand interval, to the gas and water transition zone below the Wasatch Formation. The bulk of the activity has been at the Rulison and Grand Valley/Parachute fields, where Barrett Resources is drilling, infilling and recompleting wells, and at Mamm Creek where Snyder Oil is active. Chevron, Occidental, and the DOE/NOSR are other participants in this gas play.
The Williams Fork lenticular sands gas play was discovered in 1959 by the Juhan #1 Fee well. The well had strong early gas flow rates giving rise to high expectations. When subsequent wells showed poor reserves (0.2 to 0.5 Bcf per well), this gas play was relegated to a low productivity, high cost natural gas resource. Still, these lenticular tight sands were judged to hold massive gas resources in-place of 100 to 300 Tcf, as estimated by the National Petroleum Council and the USGS. Four events have combined to revive this gas play and make it economically competitive, even during the past several years of low gas prices:Improved well siting and well completion practices have significantly improved the productivity of this gas play.
P. 505
Reassessment of Cook Inlet Platform Facilities
Authors: Visser Robert C. 
Published: December 2007

Abstract
This paper presents a methodology for performing an audit on a group of platforms to verify that the platform wells and topside facilities are being operated in conformance with current industry standards. The specific risk management audit described in the paper involved the fifteen platforms in Cook Inlet, Alaska. The paper describes the simplified procedures that were developed for the system safety reassessment. The selected procedure included, (1) the preparation and review of a database of well and process safety systems of all platforms, (2) a statistical comparison of Cook Inlet facility incidents with experience in other areas, and, (3) a more detailed review of the system safety of the wells and process facilities of three selected platforms. Fourteen of the platforms were installed in the mid-sixties, when standards for the design and operation of topside facilities did not exist. Operators, however, have, over the years, updated the facilities and no significant deviations from the industry process safety standards were found. As a result of the study the capacity of the relief and vent systems on a number of platforms are being reviewed to assure that they have adequate capacity.