bluuebunny/crossref_metadata_2025_split huggingface dataset:
Assessment of the Mounds Drill Cuttings Injection Disposal Domain
Authors: Peterson R. E. , Warpinski N. R. , Lorenz J. C. , Garber M. , Wolhart S. L. , Steiger R. P. 
Published: December 2007

Abstract
This paper presents an in-depth assessment of the fracture system created during the Mounds Drill Cuttings Injection Project. The project goal was to evaluate the adequacy of multiple injections in creating a "disposal domain". Previous papers have provided overviews of field results without supporting data or model calculations. This paper presents detailed core, log, tracer, and monitoring field data along with stress calculations, and shows that the Mounds disposal domain is more complicated and less-effective than would appear from the overview data.
The principal data defining the cuttings-filled fracture system are from cores drilled through the fracture system and imaging logs of fractures in the borehole walls. Supporting data include analyses of cuttings and induced fractures for tracers (radioactive, dye colorants, glass microspheres) injected with the slurry and fracture-diagnostic results from microseismic and tiltmeter arrays. While all field data show an extensive fracture system, core and log data show that only a few fractures have significant cuttings volume and fracture conductivity. The disposal domain created is one where there is a principal, narrow, cuttings-filled, fracture system, along with abundant, minimal-volume, offset, secondary fractures. Stress calculations also show that insufficient cuttings were injected to reorient the stress field and produce a wide range of fracture strikes. Secondary fractures probably formed from limited localized plugging or activation of intersected natural fractures. However, with sufficient additional injection, a wider disposal domain probably would have been created.
Industry Shareholder Returns and Issues Shaping the Oil and Gas Business
Authors: Marko William A. 
Published: December 2007

Abstract
In June 2000, I wrote an overview of the Exploration & Production business (E&P) for the 2000 SPE Annual Technical Conference and Exhibition. In it I discussed recent shareholder returns for a number of companies, the forces in the oil and gas business impacting company shareholder returns, how companies are addressing these forces, and the impact on people in the business. This was published in the conference proceedings as well as in the November 2000 Journal of Petroleum Technology.
At that time, four major forces were discussed. These were: 1) the view from Wall Street, 2) oil and gas pricing, 3) consolidation, and 4) capital spending trends. In the view from Wall Street section I discussed how company performance is measured and how shareholder returns compared between companies. In the oil and gas pricing section I discussed the impact of the pricing "whiplash" between the lows of 1998-99 and the highs of 2000. In the consolidation section I outlined recent mergers and acquisitions amongst the largest companies. Finally, I discussed the capital spending trends at the beginning of 2000. At that time, capital spending had begun increasing slowly with the price recovery and was initially at a lower growth rate than in previous price recovery periods.
As one considers what is occurring at mid year 2001 in the oil and gas business, these same forces continue to influence the business. In fact, they actually form the foundation of the business. Those in the business should always be concerned about Wall Street, oil and gas pricing, consolidation, and capital spending trends. They are always present though they also change over time in terms of shape and scope.
System and Method for Separation of Crude or Hydrocarbon Free and/or Disperse in Water
Authors: Aaron Padron 
Published: December 2007

Abstract
The present paper relates to a system and a method for separating a hydrocarbon containing material such as crude oil from water. The system of the present paper includes a treatment tank, a layer of a fluid having a chemical affinity for the hydrocarbon contain material being separated within the tank, for separating the hydrocarbon containing material from water without any mixing device and with a minimum level of turbulence. A distribution system for introducing the water with the hydrocarbon into the layer of chemical affinity fluid. This paper also summarize the results of the pilot test running out with different API gravity crudes, showing the effectiveness of the chemical affinity fluid for oil content reducing, from water coming from dehydration processes
Field Testing Coriolis Mass Flowmeter in Central Ghawar, Saudi Arabia
Authors: Abbasy Imran 
Published: December 2007

Abstract
Field test results of a Coriolis mass flowmeter are presented for a crude oil gathering facility located in a mature part of the Ghawar field in Saudi Arabia. Due to the maturity of the field, conventional well test measurements under low flow rate and high water cut conditions suffered from inaccuracies and gave erroneous and sometimes incorrect readings; consequently there was a need to find a replacement mode of measurement. This paper highlights advantages mass flowmeter technology has to offer under such difficult conditions. The Coriolis technology has been around for several years but its performance has not been adequately documented in oilfield applications and only recently has become economically viable and user-friendly as a result of the manufacturer's efforts to expand their application base.
In the past, 3-phase testing was necessary due to inability of conventional sensors to accurately measure flow at low and high water cut ranges. The instrumentation was expensive to maintain and large quantity of chemicals were required to achieve proper separation. Moreover, error was introduced due to an additional water rate measurement that was necessary to quantify the total water production.
This field test covered a very wide range of flow rates and water cuts and gave an insight into the improvements this technology has to offer. The test results established the accuracy and repeatability of this measurement. This technology has therefore been adopted as the primary measurement for all well testing in Central Ghawar where the water cut ranges are extreme. The field test also concluded that 3-phase testing was no longer necessary, which resulted in significant saving in maintenance and chemical costs.
Practical Approach to Determine Residual Gas Saturation and Gas-Water RelativePermeability
Authors: Mulyadi H. , Amin R. , Kennaird A. F. 
Published: December 2007

Abstract
Laboratory measurement of residual saturation (Sgr) in core samples is a matter of some debate due to the lack of a commonly accepted general method. Different protocols can lead to different values of Sgr being generated, with the associated uncertainty for simulation input. A previously conducted study indicates to the authors that steady-state displacement and co-current imbibition are the preferred methods to generate resevoir representative values of Sgr. The steady-state technique is designed to yield full-curve relative permeability data in addition to Sgr, but it is both costly and time-consuming. The objective of this paper is to introduce a method that yields both Sgr and predicted water displacing gas relative permeability data in a time-effective and cost-effective manner.
To determine their accuracy, the relative permeability curves derived from this method have been compared to those from actual laboratory test results on core samples from various water-driven gas reservoirs in Australia, New Zealand, SouthEast Asia and the U.S.A. The data predicted using our method have also been compared to relative permeability data predictions using correlations previously developed by other researchers.
The data comparisons indicate that relative permeability curves generated using our new (MAK) method not only correlate well with laboratory-measured steady-state curves, but also more closely approximate the laboratory data that predictions using previously published methods.
Implementation of Automated Expert Diagnostics to Provide Enhanced Rod Pump Surveillance at S. Belridge Field, CA
Authors: Gold David K. , Treiberg Terry 
Published: December 2007

Abstract
Recent advances in computer hardware, software, and network speed have increased the ability of engineers and operators to more effectively perform surveillance on an increasing number of wells. This paper details the implementation and benefits of a new supervisory pumpoff control (SPOC) system with expert diagnostics at S. Belridge field, CA.
Production Forecast for a Subsea Multiphase Pumping System in the Marlim Field
Authors: Baruzzi J. O. A. , Caetano E. F. , Netto J. R. Fagundes 
Published: December 2007

Abstract
This paper presents a methodology to simulate the equilibrium oil, water and gas flow rates of a well boosted by a twin-screw multiphase pump. Based on this methodology, the operational condition of the subsea multiphase pumping system to be installed in the Marlim field at Campos Basin (Brazil) is simulated for the next twenty years. For each year, the well equilibrium flow rates, and the suction/discharge pressures and temperatures are predicted as a function of the motor speed. The study shows that the average oil flow rate of the host well 7-MRL-72D-RJS shall increase, due to the pump, from about 1,300 m3/d to about 2,100 m3/d in the next ten years. In the following ten years, both oil rates, without and with the pump, decrease. At the end of the twenty-years period, the oil flow rates shall be about 700 m3/d and 1000 m3/d, respectively. The oil anticipation, induced by the subsea multiphase pumping system, is equivalent to a net present volume of around 14 million barrels for the entire system design life. A summarized description of the referred subsea multiphase pumping system is also provided in this paper.
Uncertainties and Challenges of Modern Well Test Interpretation
Authors: Al-Ghamdi Abdulla H. , Issaka Mohammed B. 
Published: December 2007

Abstract
Conceptual reservoir models are the basis for any reservoir engineering study and constitute the backbone of pressure transient analysis. The selection of the correct reservoir model is of paramount importance and cannot be overstated since the validity of the well test itself is totally dependent on the applicability of selected reservoir model. Once the proper model has been selected, various computer-aided interpretation techniques and nonlinear estimation methods can be employed to obtain quantitative descriptions of important reservoir parameters and near wellbore conditions.
Automated type curve matching, together with non-linear parameter estimation, are two great modern well test analysis tools made possible by recent advances in computer technology. In addition, the use of pressure derivative data has aided in model identification to a degree not experienced before. However, the problem of non-uniqueness in model responses threatens to undermine the accuracy and usefulness of these tools in helping to characterize petroleum reservoirs.
In this study, we illustrate the problem of non-unique model response with an example of a simulated pressure buildup test generated for a well near a sealing fault, in an infinitely large reservoir. We show that four different reservoir models can match this model response quite accurately. This makes model selection in field cases quite impossible without requiring additional information. Using field well test data from one slanted-horizontal and a short-radius horizontal well, we show, in one case how the uncertainty in the well model, as well as the value of the effective well length led to multiple matches, resulting in different estimates of reservoir parameters. In the other case, we show that without additional information from a previous test, automatic parameter estimation alone would have led to an erroneous interpretation, and wrong parameter estimates for this short-radius horizontal well.
In the field cases presented, we provide steps taken to reduce the uncertainty and non-uniqueness inherent in the process, leading to more accurate estimates of reservoir parameters from the well test data. We conclude that in many cases, integration of additional information from geology, seismic and previous well tests conducted in the same reservoir, is necessary to reduce the non-uniqueness problem and achieve an unequivocal model match.
Physical Simulation Technique For Well Testing
Authors: Bailin Pei , Ming Zeng , Qinlei Chen , Xiaodong Wang 
Published: December 2007

Abstract
The physical simulation technique for well testing is introduced in this paper for the first time. The experiments indicate that the technique can well simulate the process of well testing, and has become an effective applied technique. It has been discovered, from matching the results of the physical simulation with the exiting well test theories, that there is difference between the theoretical assumptions of constant flow rate and what happens during the well testing. The physical model with constant resistance in wellbore and constant wellhead pressure is used, and this model can match very well with the results of experiments. In authors’ opinion, this technique will be the powerful means in studying the process of well tests, especially in studying that of complex ones; and it is necessary to carry out systematic physical simulation verifications for many simple theories of well testing to solve the remained problems in the development history of well test theories.
Three-Dimensional Modeling of Structurally Complex Reservoirs: The Revancha Field Case
Authors: Pizarro Jorge , Souza Olinto , Freitas Luiz , Gomez Liliana , Comas Juan 
Published: December 2007

Abstract
In recent years, great effort has been devoted to the development of reservoir characterization techniques and the improvement of the geological description in the simulation model. As the geological complexity increases, the use of a conventional approach to represent the reservoir geometry becomes inappropriate. The goal of this work is to present a three-dimensional modeling analysis applied to a structurally complex reservoir. A field case is discussed to illustrate the approach while the integration among all reservoir management specialties is emphasized.
This paper addresses the integrated reservoir study as part of the development plan for the Revancha field, in Colombia. This is a unique petroleum field located below the Andes Mountains. Its geological features are affected by the tectonic efforts typical of compressional basins. In fact, results from the three wells drilled so far show that there is a portion of the reservoir with nearly vertical bedding. This pattern brought great difficulty to its exploitation and, also, to its modeling. The targets of the study encompassed the evaluation of the field performance, the proposal of new wells to complement the reservoir drainage and the estimation of total reserves. It was clear, since the beginning of the analysis, that a conventional approach would not be appropriate for this kind of reservoir. Therefore, great effort was applied on the 3D geological modeling of the field using state-of-the-art tools, leading to its proper representation in the flow simulator. Using a generalized corner-point grid, the production history was matched and different production configuration schemes
were tested. Since the target for increased production was the vertical portion of the reservoir, new 3D seismic data was acquired to further detail the new well locations, considering the greater uncertainty involved. Important conclusions are reached on how some of the tools available in the market can be used to model these complex reservoirs. In addition to the field data discussion and review, this paper focuses on the modeling challenges and the options chosen to overcome the difficulties.
Using Radioactive Tracer Log, Production Tests, Fracture Pressure Match, and Pressure Transient Analysis to Accurately Predict Fracture Geometry in Jauf Reservoir, Saudi Arabia
Authors: Rahim Zillur , Al-Qahtani Mohammed Y. 
Published: December 2007

Abstract
Hydraulic Fracturing program has been initiated to enhance gas production in the Jauf sandstone reservoir in the Ghawar field, Saudi Arabia. At the initial stage of the program, numerous diagnostic tests are being conducted on every well before, during, and after fracture treatment. These tests include pre and post fracture pressure transient analysis, radioactive tracer log runs during mini and main fracture treatments, production tests, temperature and production logging, complete reservoir characterization, production forecast, and history matching actual fracture treatment data. The objective of the tests and detailed evaluation is to accurately predict fracture dimension and incremental production and to calibrate stress and fracture models to optimize future fracture designs. This paper presents in detail the process of data handling, tests, and analyses, and lessons that are learned through the process of conducting the program and evaluating the results.
The paper discusses several field cases where the wells have been fractured using intermediate strength proppant. For each of the wells, careful design of the fracture treatment and detailed assessment of fracturing benefit in terms of production were performed. Design of the tests included numerous sensitivity studies on reservoir and fracture parameters to optimize treatment. Tests conducted are generally analyzed to characterize the fracture geometry, fluid invasion, and proppant transport. Consistent results were sought from the tests and using the analysis results, post fracture short-term production test data are matched.
The paper also focuses on the benefit of oriented perforation technique and how this methodology improves fracturing efficiency. A brief comparative study derived from actual cases where wells have been perforated using different methods is provided in the paper. At the end, the paper discusses the need and importance of some of the tests and the quality of the results that may be obtained from them. A table presenting results from post-fracture production tests are provided to illustrate the fracturing benefit from the Jauf sandstone reservoir wells.
Revitalization of West Hiawatha Field Using Coiled-Tubing Technology
Authors: DeWitt Mike , Peonio Jess , Hall Scott , Dickinson Roger 
Published: December 2007

Abstract
A new fracturing technique has provided a means to revitalize the West Hiawatha field located in Moffat County, Colorado. The field was first drilled in the late 1930s and comprises 18 pay sands over a 3,500-ft interval. Production is from the Wasatch, Fort Union, Lance, Lewis, Mesaverde, and Nugget horizons. The Wasatch and Fort Union horizons consist of multilayer sand bodies ranging in thickness from 5 to 60 ft.
The shallow Wasatch and Fort Union sands were traditionally completed with hydraulic fracture treatments designed to intersect multiple pay sands in a single stage. Thin sands were often ignored because of the economic limitations of isolating small intervals. Recent completions have used coiled tubing as the fracturing conduit, which enabled individual sands to be fracture-stimulated. As many as 13 coiled tubing-conveyed stages have been placed per wellbore, with individual stages placing from 20,000 to 55,000 lbm of proppant using a nitrogen foam fracturing fluid. Results obtained by selectively fracturing all pay sands confirmed a significant variation of fracture gradient in each interval. The variation in fracture gradient verified the ineffectiveness of stimulating multiple zones in one treatment.
Use of coiled tubing provides the flexibility to design fracture treatments for each sand and maximize the completed net pay. Production rates from these new completions are nearly 110% above historical rates and have significantly increased the return on capital. The average well's estimated reserves have improved by 1.8 BCF. The total field production is at the highest level in the field's 80-year history. Field production has doubled to date and is expected to triple by project end.
Beta-Wave Pressure Control Enables Extended-Reach Horizontal Gravel Packs
Authors: Coronado Martin P. , Corbett T. Gary 
Published: December 2007

Abstract
This paper describes a new gravel packing technique for extended-reach open-hole horizontal completions. The method enables gravel packing of long horizontal completions without excessive Beta-wave placement pressure.
The physical characteristics of gravel packing horizontal wells have been studied intensively in the past few years. The Alpha- and Beta-wave model has been developed to predict the pattern of sand deposition in the well during the gravel pack operation. The Beta-wave (return gravel wave) placement pressure is the main factor in determining the maximum length of a horizontal gravel pack. This pressure is limited by the requirement to install the gravel pack without exceeding formation fracture pressure, which could result in loss of control of the gravel pack and adverse effects on well productivity.
To address the Beta-wave pressure limitation, a new technique has been developed and operationally verified in field installations in the North Sea. The technique uses a special valve, or series of valves, in the inner washpipe that automatically operate to re-direct return fluid flow into the washpipe during placement of the Beta-wave. The valve eliminates the need for the return fluid to travel down the length of the screen to enter through the end of the washpipe. This prevents the accumulation of friction pressure in the screen/washpipe annulus as the Beta-wave propagates from the toe to the heel in the open-hole horizontal section of the well. Strategic placement of these valves in the washpipe string regulates the friction pressure applied against the formation below the fracture limit. Effective design and placement of the valves in the string are made possible with the aid of computational models. The new method essentially eliminates the Beta-wave pressure as a limiting factor in gravel packing extended lateral completions, and makes extended gravel packs possible that would not have been feasible using conventional methods.
This paper will describe the concept, discuss the verification-testing program used to validate the theory and review actual field operations that have been performed using this technique.