bluuebunny/crossref_metadata_2025 huggingface dataset:
Conditioning Integrated Geological Models to Dynamic Flow Data of Giant Saudi Arabian Reservoir
Authors: Al Qassab Hisham M. , Rahmeh Basem A. , Al Khalifa Mohammed A. , Awami Bassam , Sarkar Amit
Published: December 2007

A fine-scale full-field multimillion cell geologic model of a giant Saudi Arabian carbonate reservoir has been successfully conditioned to a thirty-year production/injection history. This represents the first worldwide case study of the technique for such a complicated reservoir with extensive flow history.

The initial geologic model was created based on log-derived porosity data, facies information, and a 3-d stochastic seismic inversion model. It was generated geostatistically using a sequential Gaussian simulation with collocated cokriging algorithm. It was desired to condition this initial model based on a thirty-year injection/production history.

Fast streamline simulations were performed on the geological porosity and permeability models using field injection/production constraints. The flow conditioning algorithm iteratively modified the permeability field such that simulated injection/production behavior more closely approached the supplied injection/production history. The algorithm uses analogies to seismic travel time and tomography, involving iterative linearization of the time-of-flight expression about a known initial model based on static data.

The final flow conditioned model was then validated using more thorough streamline simulations verifying improvements in the match of the simulated injection/production response to that of the historical response. Additionally, inspection of the difference between the initial and the flow-conditioned final model showed permeability modifications followed a strong directional trend consistent with well-known geological trends. Results from the final conditioned models showed more than 30% improvement in terms of history-matching than that of initial model.
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

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

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

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

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

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

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

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

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

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

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

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

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

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.
Installation of Advanced Completions in the Oseberg 30/9-B-38 B Well
Authors: Rundgren G. , Hydro Norsk , Algeroy J. , Hestenes L. E. , Jokela T. , Raw I.
Published: December 2007

This paper describes an innovative completion solution that allows commingled oil production from a well with three individual sections. The well is operated by Norsk Hydro in the Oseberg field. Included in the description are equipment selection, design and development details, installation procedures, and "lessons learned" after installation of the fully hydraulic tubing-retrievable advanced completion system. This completion provides isolation and surface production control of the three sections in Well 30/9-B-38 B, and allows viable and economical production from each.

The three fluvial sand channels were isolated using a new packer that allows bypass of individual conduits, electric or hydraulic, necessary to monitor and operate the flow control valves.

A tubing-retrievable hydraulic flow control valve was developed for this project to provide remotely controlled adjustment of flow from the reservoir. The valve uses one dedicated 0.25-in. control line to the surface to hydraulically control the choke section of the tool. An indexer adjusts and secures the choke in one of 10 positions.

The completion was successfully installed in May 2000, and the well became the highest producer in the field. Because of unacceptably high gas production, flow from the upper valve was adjusted to reduce flow from this section. This adjustment effectively reduced gas production and enhanced oil production from the lower sections. Without control of flow from individual sections, production would have been choked back at the surface because of limited gas-handling capacity. Choking at the surface would have negatively affected the overall well production.
A Simple Acoustic Wave Propagation Model for Interventionless Well Completions
Authors: Shah Vimal V. , Skinner Neal G.
Published: December 2007

The use of interventionless completion equipment is increasing in the industry. To support this trend, a system that can remotely control completion equipment by transmitting a series of precisely timed acoustic pulses has been developed. The pulses are delivered at the surface using compressed air or nitrogen and are transmitted through the tubing to the downhole equipment.

Although this process may sound simple, in reality, propagation, reflection, and attenuation of acoustic waves in tubing is rather complex. The confined fluid in the tubing forms a variable telemetry channel. This channel depends on the nature of the fluids present, the air column above the fluids, and the properties and geometry of all tubulars in the well as well as the physical construction of the completion equipment.

A numerical model has been developed to characterize the nature of the transmission channel, identify arrival times of acoustic signals, and predict signal attenuation and the decay time for multiple reflections. The success of this model has greatly increased the viability of the interventionless completion system. Signaling times and surface pulse amplitudes can be adjusted based on information provided by the model.

This paper will provide details of the numerical model and discuss the use of the model for interventionless completion as well as other applications of the model.
Completion Design and Implementation in Challenging, Extreme HP/HT Wells in California
Authors: Hahn D. E. , Burke L. H. , Mackenzie S. F. , Archibald K. H.
Published: December 2007

As producing companies search for significant hydrocarbon resources, it has become necessary to pursue opportunities in frontier geologic horizons and geographic locations. This pursuit frequently results in encountering High Pressure – High Temperature (HP/HT) environments. The petroleum industry defines HP/HT wells as those exceeding 10,000 psi and 300°F.

Several companies have drilled into HP/HT horizons in the California San Joaquin basin over the past 30 years, but generally operations were halted due to equipment limitations or due to limited hydrocarbon indications. In late 1998, a significant gas flow was identified from the Temblor formation at depths below 17,100 ft, with geologic information indicating a potential Temblor sand gross thickness of up to 3600 ft.. The pressure design basis for subsequent wells assumed an estimated equivalent pore pressure of 16.9 ppg. This information and other producing conditions, indicated potential bottomhole conditions of 425° F and 18,000 psi. Produced fluids also indicated the presence of hydrogen sulphide (H2S), which, at these pressures, dictate sour service metallurgical specifications.

These potential extreme well conditions required very detailed completion engineering design, equipment qualification, rigorous planning, and precise field execution to achieve successful well completions. This paper will detail and discuss the well completion design basis and issues; equipment/perforating limitations and qualification tests, tubular stress and loading analyses, high-density completion brine usage, and actual field operational experiences.

Numerous contingencies were planned in detail, some of which had to be implemented. The most significant contingency operation was a high pressure coiled tubing milling operation to clean out 2500 ft of formation and perforating debris, which plugged the tubing string.
Case Studies Using Advanced Interpretation Techniques for Induction Logs
Authors: Barber Thomas D. , Shray Frank
Published: December 2007

Because of their considerable range of investigation, induction-logging instruments are susceptible to a variety of environmental effects. The problems arising from high relative dip or high shoulder-bed contrasts have proven difficult to solve. The industry trend of using oil-based muds to drill these formations has prevented the use of the preferred solution—a laterolog device— in such cases. For multiarray induction tools, the problems resulting from high-conductivity contrast have recently been solved in real-time processing. Maximum-entropy inversion of the induction data is another recently proposed solution for both problems.

These two methods are now readily available to extract formation resistivity in the presence of troublesome environmental effects. The methods have been developed to meet formation evaluation needs given the reality of current drilling practice of using nonconductive muds to drill high-resistivity formations with high-conductivity shoulder beds.

This paper examines several cases of multiarray induction data ranging from near-vertical wells to high-angle wells. Several cases with high shoulder-bed contrast, from low- to high-relative-dip angles, illustrate formation resistivity measurements free from these environmental effects. The maximum-entropy method provided resistivity solutions in the presence of the single or combined effects of high relative dip and high shoulder-bed contrast. This method, however, is too slow to be suitable for real-time processing. In the vertical well cases, the maximum-entropy method and the real-time method and provide similar results in the presence of high shoulder-bed contrast. Modeling methods validated the outputs from both the real-time and the maximum-entropy processing methods.
Field Test Results Demonstrating Improved Real-Time Data Quality in an Advanced LWD Acoustic System
Authors: Leggett James V. , Dubinsky Vladimir , Patterson Doug , Bolshakov Alexei
Published: December 2007

Acoustic compressional slowness measurements are critical for geomechanics, petrophysical and seismic applications. Conventional acoustic wireline data is often unavailable due to cost constraints or well problems, thus increasing the need for acoustic Logging While Drilling (LWD). The LWD environment creates additional demands on borehole acoustic measurements as compared to wireline, due to tool strength requirements and drilling noise. These issues have consistently limited the LWD acoustic tool's ability to provide wireline equivalent data quality. The conventional LWD methods have incorporated single direction or single axis acoustic systems with short transmitter-receiver (TR) spacing (typically 4 ft). Technical features of a new acoustic LWD tool incorporating long TR spacing (+10 ft) with an array containing six four-element receiver stations to obtain omni-directional measurements will be discussed. Field test data examples will show the improved quality of this real-time measurement.

The tool configuration was optimized as a result of comprehensive modeling and lab testing of key system components. Greater source power combined with multi-frequency adjustable signature capability allowed the TR spacing increase. The system quality was enhanced due to improved software and hardware functionality. An improved receiver array configuration allows for better noise isolation and response to formation arrivals. In addition, real-time downhole monitoring of the drilling noise coupled directly into the collar allows for further data quality enhancement. Redundancy and a modular design approach were key for providing a robust and reliable system with fast tool setup and data downloading.

The field test examples will present data acquired in different drilling modes to demonstrate the improved signal-to-noise ratio for raw and stacked data in both fast and slow formations. As compared to industry standards, faster Rate of Penetration (ROP) is achievable due to enhanced downhole processing capabilities. The real time slowness results compared to conventional wireline shows the systems' ability to make comparable measurements. These field test results demonstrate an improved data quality with this new LWD acoustic system.
Enhanced C/O Logging as an Effective Cased Hole Saturation Monitoring Solution Case Histories from the Gulf of Suez
Authors: Elshahawi H. , Gad K. , William A. , Mostafa Azzam
Published: December 2007

As oil fields mature, progressively more effort must be devoted to diagnosing production and reservoir problems and to finding cost-effective solutions for those problems. One of the key inputs to any reservoir management scheme is the timely monitoring of behind-pipe fluid saturation profiles across the field. Using the C/O ratio to compute water saturation offers many advantages over conventional techniques that depend on formation water salinity. The C/O ratio relates directly to the volumes of oil and water in the formation, and conversion of C/O ratio to oil saturation is based on a very large database acquired using laboratory formations with a wide range of wellbore environments. Recent enhancements in spectral processing techniques for pulsed neutron spectroscopy tools have improved accuracy and precision of measured carbon-oxygen (C/O) ratios. These include improved elemental standards and the development of a full spectrum calibration to provide better accuracy and precision in a wider range of porosities and in the presence of gas.

Many of the Gulf of Suez fields are characterized by edge water drive mechanisms or are undergoing water flooding with different salinity water than the formation water. These conditions have traditionally presented formidable challenges to cased hole saturation monitoring, often resulting in highly uncertain results. This paper highlights several case histories from the Gulf of Suez which demonstrate how Enhanced C/O methods were used to effectively detect unswept hydrocarbons and track gas/oil/water contact movements in the reservoirs.
Riserless Drilling Technique Saves Time and Money by Reducing Logistics and Maximizing Borehole Stability
Authors: Johnson Michael , Rowden Michael
Published: December 2007

This paper describes "Riserless Drilling" methodology and the new processes being employed to redefine interval limitations in deepwater operations. This discussion includes limitations of conventional methods, types of riserless fluids in use today as well as future considerations, the benefit of new hardware designed to optimize the process, challenges accompanying this new technique and a review of several case histories using this same riserless drilling technique.
The Foinaven Field
Authors: Newcombe Gunther , Young Stuart
Published: December 2007

The Foinaven field was the first deepwater development West of the Shetlands in the Atlantic Ocean. BP and its partners took a major financial and technical risk in developing the field but wanted to ensure that any environmental and safety concerns were fully addressed. The field has been on production since November 1997 and has produced over one third of the 250mmbbls reserves, achieving a production record of 130,000 bopd in August 2000. The operational track record to date has been world class and has been achieved through a combination of integrated field management and innovative problem solving. During 2001 and 2002 over £200 million will be invested in developing new reserves and work is in progress to mature additional projects. The emphasis of this paper will be on operational experience and lessons learnt and also to highlight future opportunities and the technologies needed to deliver them.
Near-Wellbore Modeling to Assist Operation of an Intelligent Multilateral Well in the Sherwood Formation
Authors: Lucas C. , Duffy P. , Randall E. , Jalali Y.
Published: December 2007

We examine the two-year history of an extended reach dual-lateral well, in which lateral production has been controlled by downhole flow control valves to minimize water production and optimize the lift effected by a high-horsepower electrical submersible pump. We assess the impact of downhole flow control on production performance by a modeling exercise consisting of refining a region surrounding the wellbore to reproduce the observed production history, and then forecasting the performance of that refined model under alternate completion scenarios. This methodology can also be used to select valve settings that are most advantageous to production.
Fife Field UK - Rejuvenation of a Mature Asset
Authors: Bush K. R. , Wakefield J. , Shepherd M. , Beattie K.
Published: December 2007

The Fife Field situated in blocks 31/26a, 39/1, 31/27 and 39/2a (Figure 1) came on production in August 1995, with an expected field life of 4 years and reserves of 34 million barrels. The initial oil production rates from the field were prolific and in line with the field development plan, however, water production commenced soon after start-up and increased continuously in the early development wells. The impact of the water cut-development on the project economics and ultimate recovery was severely negative and as a result, an intensive sub-subsurface work programme was initiated to recover the situation.

This effort has been sustained and the field has now produced over 39 million barrels of oil. It is currently producing at 17,500 bopd. Production rates have been maintained due to the subsurface work programme, which has lead to the identification and drilling of new locations within the field. The work programme and latest wells to be drilled are described in this paper
Application of Two Methods to Evaluate Matrix Acidizing Using Real-Time Skin Effect in Saudi Arabia
Authors: Al-Dhafeeri A. M. , Engler T. W. , Nasr-El-Din H. A.
Published: December 2007

The effectiveness of acid treatment is commonly evaluated by a reduction in skin factor determined through pre-and/or post- well test analysis. However, mathematical models have been developed to monitor the change in skin while injecting acid and therefore obtaining real time skin values. This work demonstrates the application of monitoring real change in skin effect during the acid treatment with several field examples in carbonate formation.

Two real-time monitoring methods1,2 were used to capture the effect of treating fluids on the formation. The field applications using the two methods were conducted on two water injectors in Saudi Arabia to evaluate stimulation performance with in-situ Gelled Acid systems. From the calculated bottomhole pressure and injection rate, skin effect was determined as a function of time. In this manner, the effectiveness of acid injection into the formation was estimated.

The Paccaloni's method, which is a direct result of the steady state assumption, was conducted to monitor the skin factor during the acid job. The second method, by Prouvost and Economides was also used to illustrate the effect of the treating fluid on formation damage, but is based on transient flow equations. Both methods can readily be included in acid treatment monitoring; however, the latter method is preferred due to the better agreement in the field cases.

This study provides a field application comparing the two methods and demonstrates the ability to capture the effect of diversion when the gelled acid increased viscosity in the formation by a subsequent increase in skin, and also the cleanup (decrease skin) that occurred when the regular acid reacts with the formation. This study also helps field engineers to ensure that no damage remains and no excessive acid is injected. The benefits of applying these two methods result not only in an operation cost reduction but also in a higher return on the stimulation investments.
Improved Techniques of Deepwater SBM Displacements: A Case History
Authors: Messler D. , Kippie D. , Webb T.
Published: December 2007

Wellbore cleanups are an integral part of the effort to reduce formation damage during completion operations. One operation that can significantly impact the cost of the well completion is the displacement from mud to completion brine. SBM (synthetic-based mud) cleanups pose unique challenges due to the emulsifying tendency of the additives to the synthetic base fluid. In deepwater, there are at least two displacements that compound an already difficult task, i.e., the riser and the casing. This paper demonstrates how a combination of software design tools, laboratory optimization and characterization, and post job evaluation led to improved displacement practices for the deepwater wells evaluated for this paper.
Lessons Learned from a Hundred Frac Packs in the Campos Basin
Authors: Neumann L. F. , Pedroso C. A. , Moreira L. , Bezerra de Melo R. C.
Published: December 2007

This paper presents the state of the art in frac packing learned from more than a hundred operations performed in the Campos Basin, offshore Brazil.

Many reservoirs in the Campos Basin are clean tertiary age sandstones, very unconsolidated, with high to ultrahigh permeability. In this scenario, in order to get low skin completions, high conductivity fractures must be created. These can only be obtained with the use of aggressive tip screen out (TSO) techniques. For these reasons, no questions remain about the superiority of frac pack when compared with conventional gravel pack.

Since February 1996, when the first frac pack job was performed, many challenges have been overcome, especially those related to handling leak off in very high permeability and the correct use of rock mechanics properties for proper frac pack design. These include minifrac analysis for very low efficiency fracturing fluids, the use or not of spurt loss, how fracturing fluid efficiency is affected by prior calibration tests, horizontal stress anisotropy for unconsolidated sands, stress contrast for layered sandstone's, etc.

Others lessons have been learned such as: the need for high quality fluid, high quality proppant, good proppant placement, as well as calibration tests, real time design and BHTP data collection for all jobs (from electronic gauges or from live annulus).
High Temperature Acidization to Prevent Fines Migration
Authors: Huang T. , McElfresh P. M. , Gabrysch A.
Published: December 2007

As reservoirs deplete and water production increases, fines production often ensues. The produced fines then cause various forms of damage including screen plugging. To alleviate the plugging, acid washes are pumped onto the screens and then brought back to surface. Often this treatment is only a temporary solution and re-treatment is required. This paper demonstrates a more permanent solution to fines plugging through acidization of the surrounding formation and removal of the source of the fines. In high temperature wells the choice of acid must be done so that the formation is not damaged but the fines are removed. A series of tests done on clay-rich cores shows that a new organic acid in conjunction with hydrofluoric acid can successfully remove fines and stimulate production. Conventional organic acids will damage the screens at high temperatures through corrosion. This new acid has very low corrosion at high temperatures. Corrosion tests show that at 350 °F the corrosion rate caused by this organic acid is 0.001 lbs/ft2 on 22Cr for 16 hours. Core flood testing demonstrates that these organic acid:HF mixtures can effectively remove fines at temperatures up to 400 °F.
Chemical Fluid-Loss-Control Systems for Severe Environments: Taking Conventional Systems to a Higher Level
Authors: Kippie David P. , Horton Robert L. , Foxenberg William E. , Arvie Morris
Published: December 2007

Controlling fluid losses to the formation, both before and after completions, is critical to optimizing production. Fluid-loss control can be achieved through the use of either mechanical or chemical means. Chemical methods control losses to the formation by increasing the base fluid viscosity with linear or crosslinked polymers or by forming a low-permeability filter cake on the formation face. However, performance limitations have prevented the use of such traditional ‘pills’ in high-stress environments, i. e., those that include high temperature, high density, low pH, high differential pressure, and high concentrations of divalent cations, Zn2+ and Ca2+. These limitations result in accepting excessive losses or employing less-than-ideal methods.

This paper describes fluid-loss pills developed for high-stress applications for both solids-free and solids-laden systems. Among the new developments are linear gel-based fluids stable at high temperature for extended periods. For example, we present data on HEC-based fluids stable at temperatures as high as 300°F and in densities in excess of 16.5 lbm/gal. Solids-laden pills are presented that have been field tested under severe conditions including high-density zinc brines up to 18.7 lbm/gal and temperatures up to 325°F. Laboratory data are provided that demonstrate effective fluid-loss control for at least 5 days under these extreme conditions. Formation damage and filtercake cleanup results are included. Several solids-free and solids-laden systems are documented through both lab and field case histories.