bluuebunny/crossref_metadata_2025 huggingface dataset:
Development of a Series of National Coalbed Methane Databases
Authors: Mohaghegh S. D. , Nunsavathu U. N. , Jalal J. , Tovar M. , Maricic N. , Gaskari R. , Ameri S.
Published: December 2007

As the interest in coalbed methane production increases more and more engineers and scientists are becoming interested in the reservoir and sorption characteristics of different coal seams throughout the U.S and the world. As they set out to search for such information it becomes clear that finding such information is not easy. The difficulties associated with collecting such information are due to three major factors. First is the fact that development of CBM reservoirs is a relatively new phenomenon when it is compared with conventional hydrocarbon reservoirs. Secondly, companies that are in possession of such data and information are very protective of their data. They consider them company assets and are not ready to release them. Thirdly, whatever data and information that is available in the public domain is scattered in hundreds of technical papers and publicly funded project reports.

The objective of this paper is to introduce and describe the details of a series of newly developed databases that will soon become publicly available. These databases are a collection of all the publicly available CBM related data and information in one location. This series includes three major databases. First is a literature database that includes the title, authors, topics and summary of all the available technical papers and project reports related to CBM. Each entry includes a summary of the paper and other information that facilitate locating the article or the report. The database includes papers from SPE and CBM conferences and symposiums along with reports published by DOE, GRI and others.

The second database is a collection of reservoir and sorption characteristics of CBM reservoirs that has appeared in the public domain. The data has been organized by basin and field and one can identify ranges and statistics about the available data based on each basin. A reference for each piece of data is also presented. The third database is CBM well productions from different states and different local databases that has been gathered and compiled in one location for easy access. These databases are located and maintained at the Petroleum & Natural Gas Engineering department at West Virginia University.
Reservoir Characterization Using Intelligent Seismic Inversion
Authors: Artun E. , Mohaghegh S. D. , Toro J. , Wilson T. , Sanchez A.
Published: December 2007

Today, the major challenge in reservoir characterization is integrating data coming from different sources in varying scales, in order to obtain an accurate and high-resolution reservoir model. The role of seismic data in this integration is often limited to providing a structural model for the reservoir. Its relatively low resolution usually limits its further use. However, its areal coverage and availability suggest that it has the potential of providing valuable data for more detailed reservoir characterization studies through the process of seismic inversion. In this paper, a novel intelligent seismic inversion methodology is presented to achieve a desirable correlation between relatively low-frequency seismic signals, and the much higher frequency wireline-log data. Vertical seismic profile (VSP) is used as an intermediate step between the well logs and the surface seismic. A synthetic seismic model is developed by using real data and seismic interpretation. In the example presented here, the model represents the Atoka and Morrow formations, and the overlying Pennsylvanian sequence of the Buffalo Valley Field in New Mexico. Generalized regression neural network (GRNN) is used to build two independent correlation models between; 1) Surface seismic and VSP, 2) VSP and well logs. After generating virtual VSP's from the surface seismic, well logs are predicted by using the correlation between VSP and well logs. The values of the density log, which is a surrogate for reservoir porosity, are predicted for each seismic trace through the seismic line with a classification approach having a correlation coefficient of 0.81. The same methodology is then applied to real data taken from the Buffalo Valley Field, to predict interwell gamma ray and neutron porosity logs through the seismic line of interest. The same procedure can be applied to a complete 3D seismic block to obtain 3D distributions of reservoir properties with less uncertainty than the geostatistical estimation methods. The intelligent seismic inversion method should help to increase the success of drilling new wells during field development.
Projections of Marginal Wells and Their Contributions to Oil and Natural Gas Supplies
Authors: Duda J. R. , Covatch G. , Remson D. , Wang S.
Published: December 2007

Low volume wells yield a meaningful percentage of the crude oil and natural gas produced in the U.S. During 2003, about 29 percent of the crude oil and more than 10 percent of the natural gas was attributable to marginal wells. Moreover, more than two-thirds of the wells in the United States are marginal. The value of marginal well production simply cannot be overstated.

Given the significance of marginal production, "first order" forecasts of recent production and well count trends were developed in order to gain insights on the future contributions from these type wells. Volumes of crude oil and natural gas [from marginal wells] are estimated to be approximately 4 Tcfe in 2025, an increase of nearly 20 percent compared to 2003 volumes. Further, the total number of marginal natural gas wells is projected to increase by more than 160,000 to over 400,000 wells. Clearly, myriad policies and technologies must continue to advance in order to keep these wells flowing and contributing to the economic growth and energy security of the United States.
Well-Completion Strategies for Methane Gas Production from Coal Seams Using Simulation
Authors: Bilgesu H. I. , Ali M. W.
Published: December 2007

Natural gas plays an increasingly important role as a clean energy source. It is estimated that 10% of the produced gas comes in the form of methane from coal seams and the contribution of gas from coal is expected to increase to 20% in the next 10 years. There is a need to develop more gas wells that are managed efficiently. The inherent problem is the maximization of production with minimum cost. The maximum production is a function of gas content controlled by the coal properties such as porosity, permeability, pressure, desorption time and ash content. The recent trend is to develop horizontal wells to increase the recovery times by quickly dewatering the seams and to obtain gas production early in the life of the well. Developing horizontal wells in thin coal seams are expensive and the prospects need to be evaluated properly in order to maximize gas production.

Many factors affect the methane production capacity of a coal seam and to find the best well planning and design is a challenge. Many characteristics of coal such as gas content, pressure and saturation are determined. On the other hand, decisions regarding the number, location, and type of wells, completion methods, hole size and similar decisions depend on the properties of coal.

In this paper, we presented the results of a study conducted to investigate the methane gas production strategies for different coal seams. A main goal of this study is to optimize methane gas production from coal seams. Presented in this study are the effects of reservoir properties on the efficiency of selected well design.
Analysis of Non-API Industrial Sands for Use in Hydraulic Fracturing
Authors: Gottschling J. C.
Published: December 2007

Increasing demands on traditional supplies of frac sand have caused shortages of product in some areas. Alternate supplies of frac sand are available. The biggest concern with using these "non API" frac sands is possible negative impact on the well productivity.

The American Petroleum Institute (API) has developed recommended practices for quality control testing of frac sand as well as other types of proppant. Looking at the results of the testing can provide indications about possible damage to the sand pack caused by frac sand of poorer quality than what was used in the past.

The concept of dimensionless conductivity and its relationship to well productivity is helpful in understanding the damage mechanism of resulting from poor quality frac sand. Hydraulic fracture and production simulators can predict the dimensionless conductivity and translate into well productivity.
A Production-Based Method for Direct Estimation of Gas-in-Place and Reserves
Authors: Blasingame T. A. , Rushing J. A.
Published: December 2007

This paper presents a systematic method for the direct estimation of gas-in-place and reserves using only gas production data. The fundamental concept used in this work is "quadratic" rate-cumulative relation, which is given as:

(1) q g = q g i − D i G p + 1 2 D i G G p 2

Where we define the decline constant, Di, for this case as:

(2) D i = 2 q g i [ 1 − [ p w f / z w f p i / z i ] 2 ] G

The basis of our method is the development and application of several rate-time/cumulative production-time plotting functions which are derived using Eq. 1 (see Appendix A). Eq. 1 is itself derived from a rigorous coupling of the gas material balance equation for a volumetric dry gas reservoir and a modified version of the stabilized gas flow equation for a gas well producing at a constant bottomhole pressure. The proposed procedure is designed to simultaneously match the independent plotting functions (developed from Eq. 1), where we note that each function exhibits unique characteristics (e.g., a straight-line trend) which can be used as an extrapolation mechanism for estimating gas reserves.

In this work we utilize a "spreadsheet" approach in which the data and plotting functions are linked by "global" model parameters, thus ensuring consistent evaluations. We verify our methodology using a simulated case and we then illustrate the application of this method using a field case. Although theoretical considerations limit the rigorous use of the proposed methodology to reservoir pressures less than 6,000 psia, we have successfully applied of our method in practice for reservoir pressures as high as 10,000 psia.
Optimized Stimulation Solutions for a Mature Field in Kazakhstan
Authors: Utegalyev S. A. , Duzbayev S. K. , Kulbatyrov K. , Nadezhdin S. V.
Published: December 2007

Well stimulation techniques like hydraulic fracturing, which can involve large financial investments, call for a basin- or reservoir-specific approach to maximize production. Integrated solutions use a performance-based process that integrates petrophysical and reservoir characterization expertise with production and completion knowledge by developing and refining more complete interpretation and completion models based on comprehensive data. This process includes the current service standard of design, execution, and evaluation, but goes far beyond basic well stimulation, which has historically used limited data. Another important feature of the integrated solutions is a proper risk assessment based on available data. Often, especially in old fields, information is out of date, limited, or unavailable. Combining together available pieces of information through the structured process helps put together the "big picture," which subsequently provides the support for engineering decisions.

Case histories discussed in this paper illustrate how distributed teams of experts use improved models to develop solutions for old wells and future development that focuses on ultimate productivity throughout well or reservoir productive life, regardless of boundaries between various technical disciplines. Cases of application for fracturing in Nurzhanov field, Kazakhstan, are discussed.
Selection and Execution Criteria for Water-Control Treatments
Authors: Daneshy A. A.
Published: December 2007

By and large, the oil and gas industry is not happy with the success rate of treatments performed for control of excessive water produced with oil and gas. As a result, aside from treatments to stop early water break-through caused by poor quality completions, the industry views the costs of excessive water production as more acceptable than the risk of losing or reducing oil and gas production. Part of the problem is lack of clarity as to where and when water flow can and should be controlled, and the treatment selections and design considerations that can lead to successful execution.

Paper divides the produced water into two separate categories, segregated and commingled. Commingled water is often best left alone and accepted as an unavoidable part of oil and gas production. The exception is when the oil content of part of the flow stream is very low compared with the companion water. Segregated water flow can be treated and controlled with several different types of treatment. The paper discusses these and offers choices based on reservoir conditions.

Another important factor contributing to success and failure of water control treatments is the placement conditions. The paper shows that most of these are done at rates high enough to fracture the formation and this situation substantially reduces the treatment effectiveness.
Real-Time Cementing Designs vs. Actual Jobs in Progress
Authors: Creel P. , McKenzie D. , Briney M. , Pipes H.
Published: December 2007

The cementing design process has been improved by using current technology to predict actual downhole conditions, allowing both the service provider and the well operator to manage fluid positions, critical circulating pressures and surface parameters while cementing casings in wells under stringent conditions.

This paper explains how design data and real-time simulation of cementing jobs can be used to make detailed predictions of many well parameters and provide information allowing adjustments to be made during the cementing operation to alter the outcome or help improve the performance of the job. These tools can allow the operator and service provider to (1) more accurately predict cement tops, (2) change casing programs, (3) control flow-back rates and pressures, (4) monitor equivalent circulating density (ECD) on specific zones, or (5) enable personnel to create a better design for other wells in the field.

The development of computer simulations to model surface and downhole conditions has been used for more than 26 years to improve and facilitate cementing operations under different and variable scenarios. By using this engineering computer program, many cementing failures can be prevented not only before the actual cementing operation is performed, but during the operation itself. Maintaining control and predicting problems is possible by taking into account all the monitored and calculated variables on a real-time mode and comparing the outputted prediction output with the pre-job design and the actual job in progress.

Demonstrated by examples and case studies, the simulation process performs many steps needed to give precision to predictions in placement calculations. The computational process gathers information, and with multiple logical sequences, provides the most suitable solution for the scenario being studied. Multiple design program runs may be completed without jeopardizing the integrity of the well. While designing a plan, several parameters can be changed to predict the job performance or end results. Modifications or changes in various operational events for performance predictions may be used in making recommendations. Recommendations may be altered by changing such components as cementing materials, placement methods and even casing configurations to help ensure a better performance based on pre-job investigations.
New Analysis of Step-Rate Injection Tests for Improved Fracture Stimulation Design
Authors: Lizak K. F. , Bartko K. M. , Self J. F. , Izquierdo G. A. , Al-Mumen M.
Published: December 2007

Prehydraulic fracture diagnostic pumping analysis has recently improved with the use of new analysis techniques such as G-Function derivative plots, after-closure analysis, and step-rate tests. This paper analyzes various types and combinations of step-rate injection tests from many different formations around the world to determine the usefulness of these tests. The analysis uses wells with both surface and bottomhole gauge data, and in some instances, compares the results of the two. The final results of the stimulation treatments are also compared to the prefrac analysis. While the results of these tests provide information on the presence of excess near-wellbore friction or tortuosity, what is often not taken into account is that this tortuosity often destroys the usefulness of these step-rate tests in providing much sought-after data such as accurate fluid efficiency and closure pressure numbers.

The focus of this paper will be on step-up and step-down analysis, with the result being a new type of graph that provides an indepth look at the quality of these tests in any given well. Often these tests are performed and erroneously analyzed because of the effects of tortuosity, with the end result being either the data is ignored or discarded. Techniques are provided for analyzing these tests and suggestions are given to improve the results obtained from these tests.
Lessons Learned From Combined Whipstock Operation: Set Whipstock/Mill Out/Cement Squeeze/Drill Out in One Trip
Authors: Williamson R. N. , Eaton L. F. , Harrell D. , Courville D. , Long J.
Published: December 2007

ConocoPhillips pre-drilled wells for the Magnolia tension leg platform (TLP) development in 2003 using a dynamically positioned semi-submersible drilling vessel1. The Magnolia field is located in 4,674 ft of water at Garden Banks (GB) block 783 in the Gulf of Mexico. During the pre-drilling phase, two wells were successfully sidetracked out of 13.625 in. casing in one trip using an extended gage, one trip whipstock system.

The first whipstock operation was through cemented pipe and the second was through uncemented pipe, which had communication to a shallower, weak formation. This paper focuses on whipstock operations through uncemented pipe and describes the planning and execution of the first successful attempt at setting a whipstock, milling the window, squeeze cementing the window, and drilling out cement and rathole – all on one trip while using synthetic base mud (SBM).

Due to the high spread rate cost of deepwater drilling, every effort is made to reduce critical path time while managing risk and safety. Typical whipstock operations through uncemented casing can require three or more round trips to prepare a window for drilling ahead. On the GB 783 A-4 BP1 well, window milling/cementing operations through uncemented casing were conducted in a single trip. The whipstock was oriented and set at 11,080 ft measured depth (MD) in a 54° angle hole. The window was milled, the assembly pulled above the window, and the openhole squeeze cemented. After waiting on cement to set, the cement was drilled out and a successful formation test achieved. An additional 130 ft of rathole was then drilled with the mills to place the stabilizers on the next drilling assembly below the whipstock. Operations from the start of running the whipstock until the mills were laid down took 2.6 days. A total of 1,861 lbm of metal shavings was safely recovered.

This paper highlights 1) whipstock installation and window cutting operations, 2) safety and operational best practices for removing, handling, and monitoring metal cuttings that, if not removed from the hole, can be problematic for subsea blowout preventer (BOP) systems, 3) equipment modification made to mitigate risk for cementing through a milling assembly, and 4) design considerations for achieving a successful squeeze.
Applying Radial Acoustic Amplitude Signals To Predict Intervals of Sand-Stuck Tubing
Authors: Siems G. , Boudreaux S.
Published: December 2007

The reuse of existing well bores is one cost saving technique employed by oil and gas producers in mature fields. This process usually requires the removal of tubing and packers to allow the well to be deepened or side-tracked. The tubing removal process is often made difficult due to its being stuck inside casing due to mechanical binding, or binding caused by dehydrated mud or sand in the annulus between the tubing and casing. Conventional direct and indirect methods of finding the stuck point(s) along an interval of tubing, such as Free Point Indicator Tools or Acoustic Attenuation measurements, have proven themselves useful in finding the point(s) where the tubing is stuck. However, when the sticking is due to uncompacted sand that has entered the annular space between the tubing and casing, these conventional stuck pipe indication methods are often inconclusive.

Technological advancements in the design and development of slim, 1-11/16 in. OD, radial cement bond tools allow the application of a new measurement to find sand-stuck tubing intervals. These tools provide up to six independent, short-spaced, acoustic attenuation measurements distributed radially around the tool body. When recorded inside tubing, their increased sensitivity to sound attenuation, as compared to conventional omni-directional amplitude signals, allows sand intervals along the outside of the tubing to be distinguished from intervals where little or no sand is present. This information is used to select the best depth to sever or back-off the free tubing in order to reduce the interval length and expense associated with the washover process required to remove the remaining tubing from the wellbore.

An overview of conventional stuck pipe recovery techniques is discussed along with a brief explanation of applied acoustic technology. A case example of a South Louisiana well is presented to demonstrate the application and illustrate the cost savings gained by use of this newest technology.
The Impact of Nonuniform Formation Damage on Long-Term Well Performance
Authors: Yildiz T.
Published: December 2007

Formation damage along well axis may be distributed unevenly. Especially in horizontal wells, the damage around the wellbore is highly non-uniform. The literature hosts many studies focusing on the effect of non-uniform skin distribution on the transient pressure behavior of horizontal wells. There are few studies concentrating on how the uneven distribution of the skin factor affects well productivity. Furui et al. and Frick and Economides presented simple models accounting for the non-uniform formation damage around horizontal wells.

In this study, we compare the simple heterogeneous skin distribution models against the results from a 3D multisegment model. We show that the non-uniform skin models proposed by Furui et al. and Frick and Economides for horizontal wells are incorrect although the methods are simple and easy to use. Additionally, we demonstrate that the horizontal well skin formulation suggested by Malekzadeh and Tiab is inaccurate.
Tuberculosis Control—A New Approach
Authors: Moreau J. -M. , Lawhorne L.
Published: December 2007

Although the incidence of TB is receding in western countries, several factors such as resistance to antibiotics and HIV epidemic have worsened the situation in many low-income countries. Meanwhile, the globalization process has increased the frequency of travel and contacts between individuals from low and high incidence areas, therefore increasing the exposure of non-infected individuals. This is especially true for some of the oil and gas operations e.g. offshore, where the layout of the living quarters is propitious for TB transmission. Although rare, any active case of TB occurring offshore has the potential for a high impact on operations. Recently in spite of a comprehensive screening program in place for high incidence country national employees, an active case occurred on a platform in the Gulf of Mexico. That case triggered a search for a better screening tool to ensure that no detectable active TB cases enter the work place. This paper will describe our findings.
Risk-Based Reliability Engineering Enables Improved Rotary-Steerable-System Performance and Defines New Industry Performance Metrics
Authors: Wand P. , Bible M. , Silvester I.
Published: December 2007

Rotary Steerable directional drilling and logging assemblies deliver significant value to operators through improved drilling efficiency, precise well placement and effective formation evaluation.

System failure is associated with a high cost and a high pain factor. Non-productive time (NPT) is used to re-run the failed bottom-hole-assembly (BHA); hole section objectives may be compromised and there is even the potential for loss of hole section, requiring a re-drill.

This paper describes a risk-based approach to quantify and improve the reliability and performance of directional drilling bottom hole assemblies.

Extensive field data gathered while drilling fifteen million feet of hole between 2003 to 2005 has been used to drive a reliability centered design and maintenance program with the objective of improving drilling performance, improving system reliability, increasing average rates of penetration and reducing NPT.

All aspects of service delivery are considered, including mechanical and electrical system component performance, repair and maintenance procedures, job design and field operating practice.

The approach has yielded measurable improvements in rotary steerable and logging while drilling bottom hole assembly reliability and performance.

Industry metrics such as mean time between failure (MTBF), feet drilled per circulating hour (FPCH), feet drilled between failure (FBF), failure free runs and operating efficiency (ratio of NPT to operating time) are considered, benchmarking current performance and setting performance expectations for existing and future downhole systems.

The industry has a need to standardize the method of evaluating downhole drilling system performance and to understand and quantify the benefits and risks associated with the application of a specific downhole system in a given downhole environment.

This paper proposes such a standard approach, using novel BHA performance measures and an assessment of BHA complexity and well difficulty.
Field-Proven Technology To Manage Dynamic Barite Sag
Authors: Dye W. , Mullen G. , Gusler W.
Published: December 2007

Barite sag is a well recognized, but poorly understood phenomenon in the drilling industry. Industry experts have offered a variety of measuring parameters, based upon empirical data that only partially correlate with the occurrence of barite sag. The development and introduction of robust, standardized well-site techniques to predict the onset of barite sag in dynamic flow has evaded the industry. The effect of shear rate and viscosity on dynamic barite sag has been studied and quantified using new and advanced technology. Changes in the potential for dynamic barite sag as a function of shear rate, hole angle, annular velocity and eccentricity correlate with ultra-low shear rate viscosity.

Field-proven technology has been developed to predict the potential for barite sag and to provide remedial measures through ultra-low shear rate viscosity modification. This technology was originally developed and validated in the field with invert-emulsion drilling fluids. Subsequent verification and validation work showed the technology was equally valid for water-based drilling fluids. This innovative technology is well-suited for use with a variety of commercially-available field viscometers and therefore lends itself towards widespread industry use. The paper will discuss the theoretical basis for this barite sag management technology and present the viscosity levels, with corresponding shear rates, required to manage dynamic barite sag. A case is made for use of this technology as an industry standard for barite sag management and is accompanied by full disclosure of the technology for peer review. Lastly, case histories are presented demonstrating the suitability of this technology in the field and ease-of-use at the well-site.
Malaria Visa: A Globally Accessible Malaria Training and Travel Preparedness Certification Process
Authors: Dockins R. O. , Moreau J. M.
Published: December 2007

Borrowed from the concept of the "Safety Passport" the "Malaria Visa" is an on-line training and certification process for use by non-immune personnel traveling to areas where Malaria is a health risk. The person completes the "visa" process prior to departure and carries a printed certificate showing the training dates, the intended destination locations, and certification that he or she has the proper supplies and equipment.

The process ensures all personnel receive the same information, standardizes program implementation, and streamlines arrival procedures in the destination locations.
Quantifying Productivity Loss and Permeability Alteration Due to Formation Compaction During Frac-Pack Treatment
Authors: Sarfare M. D. , Zaki K. S. , Abou-Sayed A. S.
Published: December 2007

The objective in Hydraulic Fracturing is to increase well productivity and enhance or accelerate hydrocarbon recovery. Yet in soft formations, where hydraulic fracturing provides the secondary benefit of sand control, FracPack operations may result in adverse effects. These effects are more prominent in Gulf of Mexico (GOM) deepwater fields, where sands are over-pressured and highly compactive. Porosity loss around the fractured well normally occurs during FracPacks. This paper addresses this issue and quantifies the permeability loss in FracPack treatments.

Forces or pressures applied on soft rock surfaces, like those occurring during a FracPack operation, generally lead to compaction (plastic deformation). Here, we exclude Water Pack and High-Leak-off treatments. These deformations are usually accompagned by higher treatment net pressures and wider fracture widths. In recent publications (1-2), fracture stiffness and propagation were addressed during FracPacks. Considerations of both factors provide new design basis for proppants and injection schedules to optimize treatments.

The current paper addresses the leak-off and compaction responses during FracPack jobs and post-fracture productivity. The fracturing process in soft formations can be explained as expansion of the formation at the fracture tip (propagation) and a compaction of the formation on either side of the fracture face (stiffness). The compaction and stiffening of the rock at the fracture sides have great influence when evaluating fluid flow response (leak-off or production). The compaction occurs at the expense of pore space/porosity reduction around the surfaces of the fracture and creation of an extended damage zone into the formation. Permeability damage and reduction in the productivity or injectivity index follows as a result of the compaction effects.

The reported work quantifies the three basic unknowns in this problem: 1) The extent of the compaction zone and what are the dominant controlling parameters. 2) How much reduction in porosity can be expected and how is it distributed within the compaction zone. 3) The expected impact on leak-off and productivity as a result of reduction in porosity and the corresponding permeability. Existing GOM field data relating permeability and porosity/compaction will also be discussed.
From Laboratory Research to Successful Practice: A Case Study of Carbonate Formation Emulsified Acid Treatments
Authors: Kasza P. , Dziadkiewicz M. , Czupski M.
Published: December 2007

After laboratory research the pilot treatment has been done. After obtaining positive results from this treatment, BMB oil field operator begun to use emulsified acid for small scale acidizing treatment on production wells. Six acidizing treatments have been performed using emulsified acid. Oil and gas production increase was achieved after each treatment. Significant oil and gas production increase and decrease of near wellbore pressure drop was noticed during the production process.

After positive results of emulsified acid treatment have been achieved on BMB oil field, this technology was successfully introduced in wells on another oil field located on the same carbonate formation
Rigless Interventions to Failed Gravel-Pack Gas Wells Using New Resin Systems
Authors: Lightford S. C. , Pitoni E. , Emiliani C. N. , Devia F. , Valli V.
Published: December 2007

When a Gravel Pack Completion fails it usually results in the loss of production from the interval until a workover rig is available to re-complete the well. This paper describes two recent successful rigless interventions completed in offshore multi zone completed gas wells in the Adriatic Sea. A key factor in the successes of these remedial treatments has been application of two different chemical technologies applied to the proppant whilst it is being pumped into the well.

In the first well, production loss was caused by fines migration (fine silt ≤ 44 micron) into the 40/60 gravel pack sand, which completely plugged the screens and gravel. An intervention was performed which included sealing the existing completion, followed by re-perforating the premium screen using wire line guns. The interval was then fractured with a tip screen out design and a thru tubing screen was placed across the perforated screen. Critical to this treatment was the use of a surface modifying agent to prevent fines migration and plugging of the gravel pack. Production results have confirmed the correctness of the technical choice.

A different problem existed on the second well, which had a fracpac completion; in this case a screen failure resulted in formation sand and proppant being produced to the surface. The well was re-fractured through the hole in the screen and a newly developed resin was applied to the proppant to lock the proppant into place and thus repair the damaged screen without restricting the flow area with a secondary inner string. Unlike conventional resin coated proppant at low temperatures this new type of resin does not require confinement pressure and or the use of chemical flushes to cause the resin to set. Since the intervention, the well has been producing sand free at very close to the original PI.

In both cases these treatments have put back in production wells that in the past the only alternative was to recomplete using a workover rig. This paper will describe the treatment design, well operations performed, materials used and production performance of each well comparing this to a conventional recompleted well.
Behavior of a Scale Inhibitor Water-in-Oil Emulsion in Porous Media
Authors: Romero C. , Bazin B. , Zaitoun A. , Leal-Calderon F.
Published: December 2007

The use of water-in-oil emulsions (w/o) to deploy scale inhibitors has been reported in the literature as an alternative to water-based squeeze treatments. The non-aqueous nature of these emulsions has the advantage to prevent water blocking, which adversely affects oil production in aqueous squeeze treatments. Placing the scale inhibitor in a w/o or "invert" emulsion has shown in some cases the additional advantage of enhancing treatment lifetime. However, results from the literature seem contradictory and highlight a poor understanding of this technology.

The present paper aims at providing further insight on emulsified scale inhibitor placement in porous media. Preliminary experiments, using a low molecular-weight biopolymer as scale inhibitor, showed low adsorption/retention in aqueous solution. Re-formulation of the product under invert emulsion was investigated to enhance inhibitor retention.

Results from coreflood experiments, in well-characterized silicon carbide (SiC) packs provided preliminary evidence of aqueous droplet adsorption as the main retention mechanism in porous media. This was expected considering the average droplet size of 0.3 μm. The mother formulation of the w/o emulsion is a concentrate, containing 80% weight of water phase and 8% weight of active scale inhibitor. It can be diluted down to 2% water phase adding the desired oil phase without loosing stability or increasing the droplet size.

These results are a promising first step towards the development of a technically and commercially viable, environment-friendly scale inhibitor technology based on w/o emulsions.
Study and Application of Small-Diameter Separate-Layer Hydraulic Fracturing Techniques for Casing-Damaged Wells
Authors: Wang Z. , Lin Y. , He J. , Zhang C.
Published: December 2007

About 9600 casing-damaged wells were identified till 2004, up to 18% of total wells in Daqing oilfield, China. The number of casing-damaged wells is increasing at a rate of 600 wells annually. So how to apply hydraulic fracturing technique for those wells is of major importance to recover and improve oil production in related mature reservoirs. A new technique called small-diameter separate-layer hydraulic fracturing is investigated for those damaged wells whose diameter is above 105 mm. Fracturing string and its matching tools are specially designed and tested, including packer and its packing element, sand jet and safety joint. Testing results show that stabilized pressure time can maintain 5~8 minutes at the testing pressure of 40-45 MPa for all tools. Mathematical model that can be used to predict stress of casing-damaged wells was developed based on the analysis of ground bearing mechanisms under casing damages. Calculation results from the model matched very well with practical testing results. Criteria of well and layer selection will be provided based on theoretical analysis. The technique can be used to hydraulic fracture multiple layer in one time.

The technique has been successfully applied to hydraulic fracture casing damage wells and is underway to deploy in Daqing oilfield. Until the end of 2004,, fourteen wells were hydraulic fractured using this new technique. The average fracturing layer is two for each well. All treatments were successful. The average number of fracturing layers was two per well, and the average fluid increase was 20 tons/day/well, and the average oil increase reached 5.0 tons/well/day.
Overcoming Formation Damage and Increasing Production Using Stackable Frac Packs and High-Conductivity Proppants: A Case Study in the Wilmington Field, Long Beach, California
Authors: Turnage K. A. , Palisch T. T. , Gleason A. M. , Escobar D. G. , Jordan J. J.
Published: December 2007

Most successful completions in the Wilmington Field, Long Beach, CA, must address two concerns: 1) formation sand control and 2) damage bypass / reservoir stimulation. For many years the completion strategies in this field have included some combination of conventional circulating gravel packs and fracture stimulations using resin coated sand.

Recent evaluations have demonstrated that inadequate proppant conductivity is restricting well production. This led to fracture stimulation of wells with high quality ceramic proppants. Even in a modest stress environment, ceramic proppants increase conductivity and reduce non Darcy effects, thereby resulting in more productive fracture treatments.

To bypass formation damage and increase production via fracture stimulation, while maintaining sand control in an economic fashion, an annular, stackable frac pack technique was employed. The sand control treatments were designed to be durable, low skin, and provide excellent wellbore to formation connection.

The disadvantages of frac packs and ceramic proppants are complexity and cost. In older fields where margins are tight, these disadvantages may seem to outweigh the advantages and can erroneously remove frac packs and ceramic proppants from consideration.

However, the authors found that combining simple, economical, stackable frac pack tools with ceramic proppant resulted in completions with higher production and more robust economics than prior completion practices.
Minimizing Formation Damage on Sand-Control Jobs: Case Histories
Authors: Hernandez A. E.
Published: December 2007

In the Ecuadorian Northeast Area, sand production has been associated with high porosity. Certain zones where the M-1 Sandstone has porosity above 25 % have experienced a lot of sand production. High rate gravel packs have been successful and more than 30 jobs have been successfully performed. As a rule on new wells with porosity above 25% a gravel pack system is installed on the initial completion.

One important fact is the wellbore cleaning process. On the first jobs, several products were pumped to avoid severe losses to the formation; but due to the high permeability (above 3,000 mD) and low reservoir pressure it was not possible to control that. Therefore to minimize production impairment attributed by invasion of contaminants into the gravel pack and formation, a well bore clean out procedure with a non-acid formulation was implemented to remove potentially damaging solids, including filtering all the water to 2 microns.

After the gravel pack, a phosphonic / HF acid treatment is pumped to both clean the gravel from any debris coming on the pumping and placement process and stimulate the producing zone. This treatment has shown excellent results on production and has diminished the effect of the additional restriction created by the gravel pack.
Developing and Using Technologies to Manage and Reduce Greenhouse Gas Emissions
Authors: Cain J. , Lee A. , Mingst A.
Published: December 2007

Chevron shares the concerns that governments and the public have about climate change, and has developed a comprehensive program to manage its greenhouse gas (GHG) emissions. We are employing a variety of technologies to monitor and reduce emissions from our operations, and investing in research and development to commercialize new emissions reduction options.

As examples of our efforts, we are generating electricity from geothermal power in Indonesia, solar power in the United States, wind power in the Netherlands, and cogeneration in various locations. We are reducing flaring by commercializing stranded gas in Africa. We have reforestation projects in Brazil, Australia, and the United States. We are conducting research on fuel cells, hydrogen storage technologies, and advanced battery technologies, and are involved in several programs to develop, demonstrate, and commercialize carbon dioxide capture and geologic sequestration. Additionally, we have developed the industry-leading SANGEA™ system to inventory and manage our greenhouse gas emissions, and have donated it to the American Petroleum Institute. API has made the system available, free-of-charge, to the petroleum industry.
An Integrated Water Resource Management System at Balikpapan Facility
Authors: Rustamina A. , Wiraatmaja G. , Ma'arif S.
Published: December 2007

The Manggar base in Balikpapan, Indonesia, one of Schlumberger's largest facilities, provides a wide range of services to the oil and gas industry. Base operation requires a large clean water supply and wastewater management program that meets Schlumberger's and the Indonesian government's regulatory environment requirements. The challenges that Schlumberger faced locally included an insufficient clean water supply from the community, the low-quality ground water, and a sensitive coastal environment.

Schlumberger established the facility in 2000 with the objective of building an integrated water resource management system that met company and governmental requirements, and was architecturally environmental friendly.

The solution consisted of building a large environmentally friendly water pond that takes advantage of the area's abundant rainwater and integrated with a pretreatment water facility, closed-loop recyclable wastewater from washing bay and sewage treatment facility. Regular monitoring and periodic environmental audits ensure the integrity of the system.

The results have been rewardingthe working environment is cost effective and healthy. In 2003, Schlumberger received an honorary "Environment Excellence Award" from the state of Balikpapan, the first ever awarded.
Simultaneous Dynamic Killing and Cementing of a Live Well
Authors: Strickler R. D. , Moore D. , Solano P.
Published: December 2007

Drilling with casing is a method of drilling wells using casing as the drillstring. This method has been used in South Texas to reduce well costs. To help reduce well costs even further, underbalanced drilling seemed to have the potential of enabling the elimination of an intermediate casing string.

By drilling underbalanced, it would be possible to drill with a mud weight low enough to prevent loss of circulation in the shallow weak zones while dealing with the gas from the pay zones below. Drilling with casing eliminates the necessity of trips, thus simplifying underbalanced operations. However, once total depth (TD) was reached and drilling complete, it would be necessary to balance the well to allow cementing of the production casing string.

The challenge was to develop a way to kill the well so that the cement could be placed and allowed to set while at the same time not breaking down and losing circulation into the weak upper zones. This had to be done by having different equivalent circulating densities (ECD) and equivalent mud weights (EMW) up and down the hole throughout the circulating and cementing operation. In addition, this technique needed to be relatively simple and easily accomplished in the field. All this had to be done without shutting in the well or using chokes, since that would also cause breaking down the upper zone and result in an underground blowout. This paper describes the development of the required methodology and its successful field application in South Texas. This same technique can readily be applied elsewhere.
Development in Discharges and Emissions From Offshore Installations on the Norwegian Continental Shelf
Authors: Jarandsen B. , Skare I. , Raustein O.
Published: December 2007

The oil and gas industry in Norway is working on several fronts to achieve reductions in discharges to sea and emissions to air. The work has resulted in substantial improvements in recent years, and the positive trend continues. This is confirmed in the Norwegian Oil Industry Association's (OLF) annual environmental report. In 2004, 99.4 per cent of chemical discharges were environmentally harmless when discharged to the marine environment, so-called yellow and green chemicals. Discharges of environmentally hazardous chemicals in the black category have been reduced by 94 per cent during the period 2002-2004 (from 35 to 2 tonnes), whereas discharges of substitution candidates (red chemicals) have been reduced by 71 per cent during the same period (from 1022 to 299 tonnes). Emissions of CO2 and NOx have been stable during the period 2001-2004, and specific emissions are substantially lower than the international average reported by the International Association of Oil and Gas Producers (OGP). OLF's environmental report is based on the emission and discharge figures reported by the companies to the "Environment Web," a joint database for the industry and the authorities. All fields on the Norwegian Continental Shelf have been included in the reporting scheme.