bluuebunny/crossref_metadata_2025_split huggingface dataset:
Advanced Technology to Reduce Water Cut: Case Studies from the Pemex Southern Region
Authors: Romo G. A. F. , Leyva H. H. , Aguilar R. B. , Campos C. C. , Eoff L. , Darlrymple D. 
Published: December 2007

Abstract
This paper presents the results of a successful application of a new-generation polymeric relative permeability modifier (RPM) that enables treatments to reduce water cut without workover equipment. The new RPM can be bullheaded into open intervals without the need for isolating water zones from hydrocarbon zones. This treatment was applied to several wells in the Pemex southern region. As a result of the treatment, the productive life of the wells has been extended, with a gradual decrease in water cut. These results indicate high potential profitability values for mature fields with high water cut requiring a simple, low-cost treatment without the need for workover equipment or shut-in times. The new treatment can increase the hydrocarbon recovery percentage in sands that in all probability otherwise would be destined for abandonment.
This paper describes the treatment methodology, which begins with problem identification and an understanding of the origin of the water breakthrough. Next, the paper describes the new technology, which utilizes hydrophobically modified water-soluble polymers and explains how applying such polymers can control water selectively. In addition, the detailed execution of the treatment is described, followed by the very positive production results after the treatment. The results of this low-investment, high-profit technology are very promising for other wells under similar conditions in which workovers with conventional technologies would be cost-prohibitive.
Coiled-Tubing-Deployed Re-Entry Whipstocks—Technology Overview and Case Histories
Authors: Mackenzie G. R. J. , Wilson S. B. 
Published: December 2007

Abstract
This paper will focus on providing the reading audience with a general overview of the practice of utilizing a whipstock methodology with the conveyance method of coiled tubing in order to create a casing / liner window. The overview will discuss general practices, tool selection criteria and provide case history demonstration of such. The case histories demonstrated will be representative of placement of the whipstock with both electric wireline and coiled tubing with actual window milling being performed with coiled tubing and workover motors. The case histories will encompass monobore applications, through tubing re-entry environments, fluid operations and also under balanced nitrogen driven applications.
Impact of the Viscosity Reduction on the Productivity Index Using a Simulation Study in Two Networks in the Gulf of Mexico
Authors: Ramîrez-Garnica M. , Cazarez-Candia O. , Clavel-López J. , Nares R. , Schacht P. , Cabrera M. 
Published: December 2007

Abstract
The use of catalysts in crude heavy oils can improve substantially their viscosity, API and reduce the content of porphyrins, sulfur, and asphaltenes [1]. In this work a simulation study of the heavy crude oil production in networks (localized in the Golf of Mexico) was done to evaluate the effects of a smaller viscosity and a bigger API on the Productivity Index (J).
This work can be applied to study the increment of the J as well as the savings of operation costs in surface to transport and treatment of heavy oil before send it to refineries.
Simulation was done in two networks: first one, Network I performed by 8 wells offshore producing 13 °API crude oil, and the second one, Network II, producing 8 °API crude oil. In both cases, J is referenced here considering one effect of the catalyst benefits: mainly reduction of viscosity. In the case of the network producing 13 °API crude oil (with 145.26 cP @ 25°C, dead oil) the actual global J is in total 1201.5 Barrels per Day per psi (BPD/psi), and accordance to the simulation (with a modified viscosity to 1.08 cP @ 25°C) the new global J should be 5411.26 BPD/psi, which it should represent an increase of 350.38 %. In the second net similar result was obtained, the actual global J is about 549.52 BPD/psi (with a viscosity of 515 cP @ 25°C, dead oil) while the simulation result gives a global J about 2062.57 BPD (with a viscosity of 133.9 cP @ 25°C), which would represent an increase about 275.34 %.
The significance of this simulation results is very important since the economical point of view because of the better quality of the improved oil and saving costs avoiding surface treatment previous their transport to refineries.
The Development of a New Function To Improve Waterflood Predictions After Breakthrough: Field Cases, Maracaibo Lake—Venezuela
Authors: Soto B. R. , Pérez V. O. , Montiel E. 
Published: December 2007

Abstract
One of the most important parameters calculated by reservoir engineers in a waterflood project is the variation of the average water saturation with time to estimate the recovery factor. For years, that average water saturation after breakthrough has been obtained by finding the intersection of the tangent to the fractional flow-water saturation curve, fw vs. Sw, at fw = 1.0. However, this technique is subjected to errors because it is difficult to determine the exact point where the tangent to the fractional flow curve intersects the curve.
This paper discusses the development of a new function that matches with all fractional flow calculation from relative permeability displacement data and oil-water viscosity ratios. That new function has four parameters that vary according to mobility ratio. The advantage of this new function is that its derivative can be used to calculate the average saturation after breakthrough and give more accurate results in estimating the waterflood predictions and the volume of oil displaced.
We present a procedure to determine the four parameters of the new general function and the advantages of its application with field examples from some reservoirs in the literature and from Maracaibo Lake, Venezuela.
Test Design for Vertical Permeability Determination from a Conventional Pressure-Buildup Test
Authors: Ehlig-Economides C. A. , Nduonyi M. , Abiazie J. 
Published: December 2007

Abstract
Vertical permeability magnitude is critical to well trajectory and/or completion design whenever the oil is either overlain by a gas cap or underlain by an aquifer or whenever a slanted or horizontal well is planned. Various authors have provided ways to determine horizontal and vertical permeability from a pressure transient test in a well with a limited entry completion. However, none indicate a test design that will ensure that the vertical permeability can be determined.
This paper provides the necessary test design considerations for horizontal and vertical permeability determination from a conventional pressure buildup test. A standard limited entry model for the pressure transient behavior is used to determine timing for the start and end of key flow regimes for the transient interpretation. Equations that can be used to design a test for vertical permeability determination are also used to indicate ranges of reservoir, fluid and well properties that result in a successful test.
A quick look analysis procedure enables estimation of horizontal and vertical permeability directly from a log-log diagnostic plot of pressure change and its logarithmic derivative. Examples illustrate test design and interpretation applications and demonstrate that determination of vertical permeability is possible even when wellbore storage masks early radial flow and an overlying gas cap and/or underlying aquifer prevent the appearance of late radial flow.
The Role of Independents in the Oil and Gas Industry
Authors: Wadood S. 
Published: December 2007

Abstract
The Oil Industry has been witnessing many rapid developments recently. A tough competition is arising between Super Majors and National Oil Companies (NOC). Eight of the largest 10 E&P in the world are NOCs. Small Independent producers, engaged primarily in production development found a niche market. Presenting almost no competition to NOC or IOC, they offer a solution for many assets, which are of no current interest to major oil companies.
Developing of Fully Automatic Webpage Simulator for Single-Well Study
Authors: Ibrahim M. , Wattenbarger R. A. 
Published: December 2007

Abstract
Reservoir simulation is widely used to solve research problems as well as actual field problems. This is due to the limitation of analytical solutions to deal with the heterogeneity of the reservoirs and non-linearity of the diffusivity equations (i.e., for gases, properties changing with pressure). Another reason is its ability to be used in predictive methods for reservoir management purposes. The advancement of computer hardware and software technology and development of numerical solution methods have been also the factor for the increased use of reservoir simulation in petroleum industry.
Complex reservoir problems usually need a large and complex computer program. However, in some cases, a fairly small and simple computer program is enough to adequately model reservoir conditions. The main problems in using commercial simulators are grid system especially for hydraulic fracture well, dealing with the complex menus for each data component, and the time required entering the production history.
In this study, we present the fully automatic webpage simulator which has the following abilities 1) automatic gridding for single or double porosity reservoirs, 2) automatic gridding for hydraulic fractures, 3) linking to the company database in calling the production history and running predictions, and 4) design to be easy in using. The first version illustrated in this paper is already tested and used by El Paso Production Company for modeling single gas wells. The well design menus for this simulator allow users to do simulation for single well with just a few mouse clicks without spending much time in entering any data due to this simulator have the ability to load the data from the database.
Successful Implementation of Well Management to Increase Hydrocarbon Production: A South Region of PEMEX E&P Case History
Authors: Arévalo-Villagrán J. A. , Gutiérrez-Acosta T. , Ascencio-Cendejas F. , Cinco-Ley H. , Lozada-Aguilar M. A. , Lysandrou M. 
Published: December 2007

Abstract
An integrated analysis of technical information from 459 wells that were shut in or having production problems within five Integrated Business Units in the Southern Region of PEMEX E&P, identified production increase opportunities of more than 145,000 STB/D of oil and 323 MMscf/D of gas. This paper presents the applied methodology and the results obtained from a project based on well management to optimize the recovery of hydrocarbons of the identified opportunities within these business units with minimum investments. The successful implementation of this project was based on the careful selection of highly qualified technical personnel that formed the nucleus of the working multidisciplinary teams that contributed to the increase of well productivity from the selected fields. The implementation of the concept of team work coupled with the application of selected technologies to identify and exploit potential opportunities made it possible for these business units to increase the production of crude oil over 67,635 STB/D and gas to over 111 MMscf/D from workover of 179 wells within 9 months thus achieving a production increase of 7.95 MMSTB of oil and 12.8 Bscf of gas. This increase in production made possible for this region to maintain a production plateu of 500,000 STB/D and 450 MMSCFD, offsetting natural production decline and loss of production due to a strong water invasion of wells. A profit/cost ratio of 15.1 has been obtained. In addition to the value added of production increase through this visionary management approach, the following benefits were obtained: learning and applying the team work approach of well productivity, adaptation to a new cultural change of working as teams to solve difficult problems, training and transfer in diverse methodologies, and software technologies from the interdisciplinary teams to the technical personnel of PEMEX E&P, and specific well data information certified that can be used to evaluate diverse reservoirs studies.
A New Method for Acid Stimulation without Increasing Water Production: Case Studies from Offshore Mexico
Authors: Reza G. H. , Soriano E. , Eoff L. , Dalrymple D. 
Published: December 2007

Abstract
Successful acid stimulation requires a method to distribute the acid between multiple hydrocarbon zones. Since almost all producing wells are inhomogeneous, containing sections of varying permeability, this can be a huge problem. In addition, the water saturation of the various zones plays an important role. Since acid is an aqueous fluid, it will tend to predominantly enter the zones with the highest water saturation. These water zones are also often the highest permeability zones, so acid stimulation will often result in large increases in water production. There are many negative aspects to increased water production, such as increased lifting and disposal costs, increased corrosion, etc. This paper describes the use of a new low viscosity system that inherently reduces formation permeability to water with little effect on hydrocarbon permeability, and also diverts acid from high permeability zones to lower permeability zones.
This new system has been used in offshore Mexico in the Chuc, Caan, and Pol fields among others over the past year. During this time, over 30 wells have been treated with the new system. Most standard acid treatments in this field result in increased hydrocarbon and water production. The new system has resulted in increased hydrocarbon production with no increase in water production, and in some cases a decrease in water production. Details from several of these jobs will be presented showing the diversion and production results.
Horizontal Well Drilling and Completion Schemes Consider Future Stimulation To Optimize Production
Authors: Surjaatmadja Jim B. , McDaniel Billy W. , Case Leonard R. , East Loyd E. 
Published: December 2007

Abstract
The importance of ensuring maximum production of a well throughout its lifetime is unquestionably very important for the operator. Well lifetime starts from the beginning (i.e. drilling and completion) and proceeds through production, production decline, and finally consideration of a stimulation treatment. In situations where all wells are vertical, this process has become well understood. A different situation exists however when horizontal completions are used because only 20 years of practice is behind us. Nevertheless, one thing is clear: whether the horizontal well is drilled in a low- or a high-permeability reservoir, there will always be a need for stimulation and re-stimulation. Unfortunately, too many horizontal wells were completed with no plans for stimulation, and often, these wells can not be stimulated effectively because of mechanical or reservoir limitations. Had these wells been constructed with stimulation in mind, extensive preplanning could have helped overcome such limitations beforehand.
This paper discusses many field and reservoir aspects such as formation geology and localized tectonics that may influence proper well placement for future applications of fracture stimulation. Emerging new completion tools and processes that enable fracture stimulation should be evaluated to allow wells in less promising areas of the reservoir to become economic contributors rather than net losses on the ledger. All such considerations should be incorporated in the general recovery plan for a field, as well as proposed completion schemes (especially perforating techniques) that might be used to produce the well when stimulation is not required, keeping in mind that stimulation is still a future option. Different completion schemes may have to be used for each well based on its position within the field. Field experience with supporting data will be presented and discussed in depth, as well as conventional and new stimulation options that would optimize specific applications.
Consideration for Future Stimulation Options is Vital in Deciding Horizontal Well Drilling and Completion Schemes for Production Optimization
Authors: Surjaatmadja J. B. , McDaniel B. W. , East L. E. , Pyecroft J. 
Published: December 2007

Abstract
Thorough planning of a well, or better yet, a field, to determine how each well can provide maximum production throughout its lifetime is unquestionably very important to the operator. For fields of vertical wells, this process is well understood. For horizontal completions, however, only 20 years of practice are behind us. For lower permeability reservoirs, the theory that using horizontal wellbores can eliminate fracture stimulation has proven to be false. Today, the assumption that moderate to higher permeability reservoirs will never be candidates for stimulation is also being challenged by a high number of non-economic wells. Too often, we find many of these horizontal completions need stimulation but are not candidates because of the mechanical limitations of the completion plan.
This paper discusses the many field and reservoir aspects, including formation geology and localized tectonics, that can influence proper well placement for future applications of fracture stimulation. The evaluation of emerging completion tools and processes that enable fracture stimulation should be nurtured to allow wells in less promising areas of the reservoir to become economic contributors and not net losses on the ledger. These wells must be incorporated into the general recovery plan for a field and taken into account in completion schemes (especially perforating techniques) to best produce the well when stimulation is not required, yet keeping stimulation as a future option. Different completion schemes may have to be used based on the position of the well within the field. Field experience with supporting data will be presented and discussed in depth, as well as conventional and new stimulation options that would optimize the specific applications.
Design and Implementation of Retention/Filtration Media To Improve Heavy Oil Production
Authors: Underdown David R. , Hopkins Sam 
Published: December 2007

Abstract
The factors that control the performance of sand control screens that use woven metal mesh as the filter media; i.e, commonly called "premium screens", are not generally well understood by the end user. The end user is provided a premium screen with a woven metal mesh with some weave type, and told the sand control screen is better than the other premium sand control screens on the market. The end user is told that the premium sand control screen uses such material as Dutch, Dutch Twill or a Reverse Dutch Twill woven metal mesh, and some cases the manufacturer will promote the benefit of multiple layers of woven metal mesh filter media in the sand control screen to control the sand. All this information is interesting, but the end user really does not understand the significance of the information.
This paper presents the results of a study to evaluate the effect of different woven metal mesh weaves on the performance; i.e., dirt holding capacity and plugging tendency, of media commonly used in sand control screens for deep water and heavy oil completions. The work also introduces a new approach to designing sand control screens that use woven metal mesh material. The performance criteria used in the evaluation of different designs for the filter media include control of solids, and the impact of particle size distribution of the formation on the plugging on the surface and in the filtration media. Laboratory testing demonstrates that use of a different type of construction of the retention/filtration media allows for greater performance than currently used media in sand control screens.
The significance of the approach discussed in the paper is the ability to design and engineer a sand control screen with a retention/filtration media for a given particle size distribution of the formation that allows for maximum oil production and minimum solids production. Critical to the success of this approach to designing sand control screens is the thorough evaluation/testing of multiple media types to create the "formation specific" design.
Evaluating Inter-/Intrazonal Isolation
Authors: Tiwari Anil Kumar , Rajasekaran Pitchai , Katare R. P. 
Published: December 2007

Abstract
There are two major challenges in achieving perfect and durable inter/intra zonal isolation; accurate planning of cementing operations according to well specific requirement and realistic evaluation of operational performance for attainment of the objective. Prevailing practice for evaluating cementing performance, in the industries is not authentic enough to justify remedial operations planned. It just based on readings of graph while other critical aspect such as phenomenal formational response, influence of other processes which are being performed / to be performed prior to or post cementing operations like hermetical testing of casing, various activation/stimulation processes which could affect the quality of evaluation/performance are overlooked.
The objective of study is to address all the relevant aspects while interpreting the logs and develop a methodology for making precise and realistic evaluation of logs for avoiding many futile operations which ultimately affects the productivity and life of the wells.
The procedure adopted for formulation is as under Compilation / analysis of log data field wise Compilation / analysis of production trend with reference to cementing performance.
Mathematical model exhibiting impact of stresses produced during pressure testing at various stages of cementing through well completion process and its influence over logs and cement bond integrity.
Influence of formational image on sonic log graph.
Organization of all logical and mathematical data to design and develop realistic-precise methodology.
This paper provides (i) an innovative approach to the prevailing practice (ii) helps to develop a methodology which may utilize all those data presently ignored (iii) to devise a precise diagnostic tool in the form of software to reduce human error, this is under conceptual stage.
This methodology may limit its application to the development field as exploratory wells may not have sufficient quantum of data for uploading in the software for analysis.