bluuebunny/crossref_metadata_2025_split huggingface dataset:
Evaluating Fracture Stimulation Treatments in Northern Mexico by Integrated Reservoir and Fracture Treatment Analysis
Authors: Robinson B.M. , Rascon Austreberto Rios , Hernandez Crescenciano Perez , Sanchez Bujanos Juan M. 
Published: December 2007

Abstract
Several studies have been performed recently that have focused on reevaluating the original fracture treatment designs performed in various low permeability gas fields in the Burgos Basin of northern Mexico. The primary goal of these studies was to determine if the fracture treatments were achieving optimal stimulation of the reservoirs. Results of this work have indicated that the propped fracture half-lengths achieved in the past are approximately 40% to 50% of the original designed half-lengths. The main reason for the shorter fracture lengths is that the created fracture heights were greater than expected.
The studies have provided better descriptions of individual reservoir properties and vertical stress profiles. These results are now being used in both reservoir and fracture models to design more optimal fracture treatments. These new fracture treatment designs have increased production from 50% to 300% over previous fracture designs.
P. 415
Hydraulic Fracture Stimulation Design and Well Performance in Nonconventional Reservoirs
Authors: Conway Michael W. , Barree Robert D. 
Published: December 2007

Abstract
In recent years there have been numerous reports of the application of state-of-the-art methodologies to hydraulic fracture treatment design. One of the biggest problems in applying advanced technology to stimulation design is the acquisition of input data for computer simulations.
Over the course of the last three years, a cost effective systematic methodology has been developed for acquiring the reservoir properties required for hydraulic fracture treatment design. Dipole sonic logs coupled with a water injection/fall-off test in combination with a 3-D hydraulic fracture design simulator have been used to understand reservoir characteristics and to design stimulation treatments based on reservoir characteristics.
This methodology has been applied to conventional tight gas reservoirs as well as coalbed methane reservoirs, and has allowed the optimization of the stimulation treatment based on reservoir characteristics. There are numerous examples of successfully completed stimulation treatments that have failed to produce. This paper recounts examples for both coalbed methane and conventional reservoirs where the treatment type can be compared to reservoir characteristics and production responses.
P. 421
Simplified Productivity Equations for Horizontal Wells Producing at Constant Rate and Constant Pressure
Authors: Helmy M. Wael , Wattenbarger R.A. 
Published: December 2007

Abstract
This paper presents a simple model to calculate the productivity of horizontal wells producing at constant flowing bottomhole pressure, Pwf, or constant rate from bounded reservoirs. We propose new, easy-to-use correlations to calculate the shape factor and partial penetration skin for both cases. The shape factor is calculated using an analytical solution of a fully penetrating well; and the partial penetration skin is calculated using a numerical solution. The correlations are developed using nonlinear regression (with R2 of 99%) of more than 800 numerical simulation runs for different reservoir aspect ratios, well locations and well penetration ratios. The productivity of wells producing at constant Pwf can be quite different from that of wells producing at constant rate. The models proposed in this paper are only approximate. In many cases they proved to be more accurate than other methods currently available in the industry. However, errors could be generated when the proposed models are used outside the range of applicability of the correlations.
P. 379
Optimization of Stimulation Chemistry for Openhole Horizontal Wells
Authors: Morgenthaler L.N. , McNeil R.I , Faircloth R.J. , Collins A.L. , Davis C.L. 
Published: December 2007

Abstract
Successful completion of openhole horizontal wells requires removal of potential impairment from the near wellbore and formation face. Impairment can reduce well productivity and lead to failure of sand control screens due to plugging and erosion. Shell has adopted the practice in the Gulf of Mexico of employing drill-in fluids with acid soluble bridging, and weighting agents for all openhole drilling and extensive displacement and acid cleanup procedures during horizontal well completions. Drill-in fluid and filtercakes are removed with specially formulated sweeps and by attainment of sufficient velocity to achieve effective displacement. Filtercakes are removed with specially formulated washes applied using washcups or coil tubing to ensure that cleanup formulations contact filtercake materials.
Drill-in fluids and clean-up systems must be specially formulated arid evaluated for specific applications. We have adopted a suite of laboratory screening tests to evaluate formation damage and removal chemistries to ensure that each well is effectively cleaned. These tests can also be used to evaluate new fluid systems before taking them to the field. Our approach in this instance is to compare data from new fluids to results obtained with fluids we have a successful field track record with. In this paper we will review these procedures arid results with results with a variety of fluid systems.
P. 415
New Water-Soluble Perforation Ball Sealers Provide Enhanced Diversion in Well Completions
Authors: Bilden Dean M. , Lacy Lewis L. , Seiler Fred H. , Ischy Noel D. , Fox Craig S. 
Published: December 2007

Abstract
A new water-soluble perforation ball sealer has been developed and successfully used as a substitute for conventional ball sealers. They also can and have been used in situations where conventional ball sealers would not be an option due to the potential of creating undesired costly workover operations.
The introduction of a degradable or water-soluble ball sealer signifies a major breakthrough in ball sealer technology. This paper discusses the new ball sealer chemical and physical properties and development methodology. Laboratory testing techniques and methods are presented.
This paper focuses on the laboratory testing conducted during the development phase and the data generated to support proper application in the field. Also, the potential benefits of water-soluble ball sealers are presented along with examples of successful application in wells.
P. 427
Proppants, We Still Don't Need No Proppants - A Perspective of Several Operators
Authors: Walker Ray N. , Hunter Jeffery L. , Brake Al C. , Fagin Paul A. , Steinsberger Nick 
Published: December 2007

Abstract
In SPE 38611 "Proppants, We Don't Need No Proppants" data showed that fracture treatments using treated water and very low proppant concentrations (waterfracs) were very successful in the East Texas Cotton Valley sandstone. The paper presented limited initial results from one operator in one field. Following this paper a more comprehensive set of production comparisons of wells completed with standard frac jobs and waterfracs since 1996 for several different operators in the East Texas area are presented. Analysis of offset comparisons, economics, and other benefits are described from the aspect of several different operators.
Conclusions will point out the cost savings and the ability to exploit marginal reserves with this technique. There will also be a perspective from each operator. The waterfrac technique has led to widespread discussions among many operators in various tight gas plays. Many operators are experimenting with the technique and experiencing excellent results. This technique is a major contribution to the reduction in completion costs in wells that must be hydraulically fractured. The industry has experienced a major inflation of well construction costs and this technique will be of paramount importance in our efforts to keep costs down in order to continue to develop tight gas reserves. Techniques such as these require many months of production in order to analyze to determine the actual results. Several techniques and the perspectives of several operators and how they make these important decisions will be presented here.
P. 497
Optimized Hydraulic Fracturing Improves Oil Production in the N'Dola Field, Offshore Angola
Authors: Bagzis John M. , Wehunt C. Dean , Neubauer Edward B. , Jansson Raymond P. , Tjoonk Richard , Roueche Lee N. , Scarborough Ben 
Published: December 2007

Abstract
Conventional hydraulic fracturing has been widely used to improve production within low permeability formations for the past 50 years. However, it is not as widely known for improving production within more moderate permeability formations. This paper pertains to the use of hydraulic fracturing in one such formation, the Pinda Sandstone, within the North N’Dola field, offshore Angola.
Hydraulic fracturing within this field was optimized utilizing advances in fracturing treatment technology for these deviated wells. These advances include using various point-source perforating schemes and proppant slugs to mitigate the creation of multiple fractures and near wellbore friction problems. These perforating schemes are compared as to length of perforated interval, shot phasing, number of shots per foot, and gun diameter. Also, proppant slug sizes and concentrations are discussed as to relative benefits in mitigating near wellbore problems associated with fracturing of deviated wells. Real-time data acquisition and analysis, including step-down testing, were included as part of the optimization process. Thirteen of the 15 fracturing treatments incorporated a live annulus for pressure monitoring purposes. Minifracs were utilized on every fracturing interval as a combination fluid efficiency test, fracturing model confirmation, and to carry the proppant slugs. Computer processed, stress logs were successfully used as an aid in selecting intervals with lower fracture initiation pressures. A continuously mixed, high-temperature, borate crosslinked, fracturing gel made from seawater was successfully employed. Also, a high temperature, encapsulated scale inhibitor was also used to control scaling problems that have plagued offsetting fields.
Production clean up procedures are discussed including the production ramp up procedures to mitigate proppant flow back, and the use of a hydrocylone desanding unit for proppant removal at the surface. This paper will also discuss the logistical challenges that this project created including the use of skid mounted, fracturing equipment and materials offshore aboard a tender rig.
Field Hydraulic Tests Improve HPHT Drillng Safety and Performance
Authors: Isambourg P. , Bertin D. , Brangetto M. 
Published: December 2007

Abstract
For the Elgin-Franklin UKCS fields, drilling of the HPHT phase is critical due to the narrow margin between formation pore and fracturation pressures. This problem is accentuated by the extreme temperature (up to 205C - 400F) and pressure (up to 1200 bar - 17400 psi). A new generation of down-hole Pressure While Drilling (PWD) tools allows a better real-time monitoring of the bottom-hole pressure, but cannot withstand the extreme temperature of the entire HPHT phase. Furthermore, down-hole and surface pressures are dependent on complex hydraulic phenomena which make predictions challenging. Consequently it was decided to perform hydraulic tests before drilling the HPHT section of the well 22/3Oc-G4 (first Elgin development well), in order to quantify the surface and down-hole pressures and temperatures on several operating conditions: circulating (with an without pipe rotation), tripping and flow check. Gelation tests, trapped pressure as well as pressure transmission tests were also performed.
Objectives of these tests were: to better understand some complex down-hole physical phenomena, to prepare practical guidelines (such as mud density variations, Equivalent Static Density values, ECD function of flow rate and pipe rotation, mud compressibility values, tripping procedures, etc…) before drilling HPHT sections, to check reliability and accuracy of new Real Time PWD tools, and to collect accurate well data for further hydraulic software packages validation or improvement.
These procedures led to great benefits, both in terms of safety and performance, when drilling the HPHT phases of the well: results were considered as highly positive. This paper details down-hole measurement procedures and results, operational guide lines, tools performances, lessons learnt, and explain how to cope with sources of possible discrepancies between actual values and software predictions.
P. 551
Use of Fractionation Column in an Offshore Environment
Authors: Li K.J. 
Published: December 2007

Abstract
The Draugen field was the first offshore platform installed in the Mid-Norway offshore acreage. In addition to the challenge of the harsh environment, several innovative designs were implemented in the development.
Due to the unique reservoir fluid composition, low GOR of 55 m3/m3 and 9% propane content, the conventional design of recycling condensate from compression to the crude separators was not very cost effective. By installing a condensate stabilisation column operating at a high-pressure of 24 bara and by minimizing the recycle streams, the installed compression horsepower was reduced by half. Since the start up of the facilities in 1993, the condensate stripper was fully utilized when the production capacity was doubled while still maintaining the single train concept. Recently the operation of the platform was further optimized to enhance the value of the crude and minimizing the discharge of VOC (volatile organic components) from the crude product.
P. 387
An Approach to Real-Time Optimization of the Central Gas Facility at the Prudhoe Bay Field
Authors: Clay Roger M. , Stoisits Richard F. , Pritchett Michael D. , Rood Robert C. , Cologgi John R. 
Published: December 2007

Abstract
As computer costs continue to decline and computer power increases, the technologies of advanced control and real-time optimization become more economical and more easily justified for process plant operation. Upstream oil and gas facilities previously thought not to be candidates for advanced controlor optimization should be given new consideration. The benefits to be realized are many and include reduced operating margins, improved recovery, improved throughput, reduced emissions, reduced utility consumption, and improved safety and operating consistency. As a means to demonstrate the benefits of real-time optimization in an upstream facility, ARCO developed an open-loop prototype optimization tool using existing process models and an expert system operator interface. The north slope Alaska Prudhoe Bay Central Gas Facility was chosen for the application because of existing model development and the potential economic return. In short, the application runs as a process monitor which triggers the model and optimizer when conditions deviate sufficiently from the previous optimization run. Set points are then calculated and displayed for the operator in an advisory manner.
P. 399
Redevelopment and Management of the Magnus Field for Post-Plateau Production
Authors: Day Simon , Griffin Tim , Martins Paul 
Published: December 2007

Abstract
Magnus is the most northerly field in the UK North Sea, with 14 platform and two subsea producers, and 13 injectors of which 8 are subsea. After 12 years of plateau production at 140,000 bopd, the field went on precipitous decline in 1995, with an underlying decline rate of 60% per annum. Although there had been significant preparation and investment for decline, the severity of the well-related problems had not been anticipated. Wells producing over 20,000 bopd fell over in a matter of hours as a result of severe barium sulphate scaling, amongst other factors.
This paper discusses the causes of the severe declines, the increasing evidence of reservoir complexity, and the re-engineering of the reservoir development that equipped the field for post-plateau production. During the first three years of decline, all production wells were either side-tracked or had major interventions to maintain production, as we moved from multi-zone to single zone completions. Crucial to the success of the performance recovery has been the drilling of several injectors, targeted to support specific zones/areas. Facilities upgrades were also made with increased water-handling capacity, gas lift capability, upgraded water injection pumps and a subsea injection manifold all being added.
The subsequent reservoir and well management strategies used are discussed, together with a summary of lessons from the new wells. The main keys to success of the programme are presented, including base production focus and scale management operations. As a result of the re-engineering, the base decline rate has been substantially reduced and manageability has been restored to the field. The lessons learned on Magnus may have relevance for future developments reliant on a small number of wells, particularly if they are subsea.
Effective Evaluation of Fluid Mobility From Stoneley Waves Using Full Biot Model Inversion: Two Case Histories
Authors: Pampuri F. , Rovellini M. , Brie A. , Fukusima T. 
Published: December 2007

Abstract
There are efforts in the oil and gas industry aimed at the evaluation of a continuous permeability profile. Since the introduction of the high-fidelity digital sonic tools, the high quality Stoneley waves available, can be used to determine a continuous fluid mobility profile along the well.
The methodology to obtain an accurate determination of permeability from Stoneley has been the subject of much research. This paper presents the quantitative fluid mobility results obtained from the Stoneley waves with the latest processing techniques in various oil reservoirs. The results were compared and integrated with other mobility measurements such as laboratory core analysis, formation testing and nuclear magnetic resonance logging (NMR), to determine the significance, strength, and weakness of the Stoneley technique. The methodology, is based on inversion of a propagation model that uses the full Biot elasticity theory. This results in a continuous in-situ fluid mobility curve with a quantitative evaluation of its uncertainty.
Two well cases are presented: one from a layered sandstone reservoir drilled with oil based mud, and the second from a thick clastic carbonate reservoir drilled with water based mud. In these examples, the computed Stoneley mobility profile is consistent with the degree of the heterogeneity of the formation. The calculated fluid mobility profiles show a high degree of correlation with core permeability measurements, NMR permeability curves and formation test results.
These examples show that the methodology can be applied with success both in siliciclastic and clastic carbonates with porosity greater than 8-10 %.
The computation is sensitive to the input porosity (effective) and the application to real data shows that the most critical input parameters are those linked to the mud (slowness and attenuation) and to the formation fluid (compressibility). A practical method is proposed to determine these parameters, In these cases the Stoneley mobility curve is comparable to the "absolute" permeability.
The Stoneley fluid mobility curve can provide valuable information both for exploration and production phases. Potential applications complement formation evaluation, optimize production testing programs and strategies, enable early identification of layered reservoirs and static/dynamic reservoir modeling.
P. 401
Mechanical Strength of Reservoir Materials: Key Information for Sand Prediction
Authors: Zhang Jiaxiang , Rai Chandra S. , Sondergeld Carl H. 
Published: December 2007

Abstract
The mechanical strength of a reservoir formation is the most crucial information required for predicting sand production and recommending sand control completion. The only reliable technique, so far, to obtain the formation strength quantitatively is to perform laboratory tests on core samples. The laboratory tests require substantial volumes of cores which, in most cases, are not available. In this study, we present a new method to avoid this restriction. The significance of this approach is its simplicity and efficiency in constructing a reliable mechanical failure envelope. The key results of this study, based on measurements on a variety of sandstones, are:Sandstone formations are characterized by a single normalized failure envelope. This universal curve makes it possible to construct the failure envelope for a sandstone formation from the knowledge of critical pressure.There exists a correlation between the critical pressure and the compressional wave velocity (at equivalent depth of burial).The failure envelope for a sandstone formation can then be Constructed simply from compressional wave velocities. These velocities are generally accessible from conventional logging data.
P. 423
A Coupled Model to Predict Interformation Flow Through an Abandoned Well
Authors: Striz Elise A. , Wiggins Michael L. 
Published: December 2007

Abstract
This paper presents a novel approach to predict flow between two formations coupled by an abandoned well. A steady state abandoned well model is derived analytically and applied using a series of steady state's to create the transient flow response. The model is verified by comparison to the results of a transient analytical interformation well model for a single injector given by Avci. This model is the first to include true pressure losses in the abandoned wellbore calculated from established equations for turbulent or laminar pipe flow, plugs, and a casing perforation. The model can also predict flow behind pipe through an open or plugged annulus or a fracture in the annular plug. Finally, the model is the first to incorporate the effect of pressure variations due to production or injection in the overlying formation on the well flow.
Application of the model in a single phase simulation demonstrates the impact of abandoned well location and condition, rock and fluid properties, and initial pressures and well operations in the coupled formations on the abandoned well flow. Evolving pressure distributions in the coupled formations may move flow up or downhole. Pressure losses in the wellbore or behind pipe through plugs are shown to preclude flow. The model is also applied to a field case to demonstrate its use as a prediction tool for abandoned well transport. As opposed to the limited analytical solutions or complex numerical simulation methods currently available, the new abandoned well model provides a simple means to determine flow for realistic field conditions.
P. 419
Oil/Water Slugging of Horizontal Wells - Symptom, Cause and Design
Authors: Barrett Nathan , King Dave 
Published: December 2007

Abstract
A maturing BP oilfield called Wytch Farm has recently experienced operating problems with its ESP wells. Large fluctuations had been seen in flowrate, pressure and supply current. The fluctuations were recorded for several different flowrates, before being analysed. The analysis of the data gave a suspicion that these wells were slugging in the wellbore before the pump inlet. However only oil and water are known to exist in the wellbore in this particular field and this type of behaviour had never been seen before in this oilfield.
Discussion about the mechanisms of oil-water slugging, and also why these wells have recently started to slug are included.
Transient analysis of the well using OLGA (ref 1.) gave a good representation of the wellbore and a degree of confidence that we could predict the flow pattern. Further analysis led to a better understanding of the mechanisms Causing these operational issues. The end result is that recommendations can be made for future wells and indeed the same analysis is recommended before they are completed to avoid this unusual problem in the future.
P. 461