bluuebunny/crossref_metadata_2025_split huggingface dataset:
A Novel Program for Processing Acid-Stimulated Well Returns on Offshore Platforms
Authors: Brown J. Mike 
Published: December 2007

Abstract
Offshore oil and gas wells sometimes require stimulation to remove formation damage and improve production. The chemicals used in stimulation packages and the low pH of the fluids can cause a difficult to resolve emulsion that creates upsets in the operation of the platform crude oil and water treating systems. These upsets result in oil that does not meet pipeline specifications and water that cannot be discharged overboard. Out-of-spec oil is temporarily stored in a wet oil tank; however, on offshore platforms storage is limited and when the capacity is exceeded the entire production from the platform must be shut in until the out-of-spec fluids can be processed or shipped to a land-based handling facility. The low pH and high organic content of the water from the stimulated well returns can cause upsets in the water treatment system resulting in overboard water discharge that is out of compliance. This also can result in a shut down of production.
A novel program has been developed which eliminates the difficult to resolve emulsion resulting from stimulated wells by using a unique combination of products custom tailored for each offshore production platform. The program prevents out-of-spec oil by allowing for complete emulsion resolution in the test separator. This eliminates the possibility of a complete production shut-in period. The water from the test separator is processed in a two step treatment which removes free oil and dissolved organics to a level that is acceptable for overboard discharge. This system generates no waste byproducts. The oil and gas production of a platform can be maximized by pursuing more aggressive stimulation schedules on single or multiple wells without risking an out of compliance operation or excessive disposal costs.
Identifying Opportunities to Increase Oil Recovery from Fluvial-dominated Deltaic Reservoirs in Oklahoma
Authors: Knapp R. M. , Yang X. 
Published: December 2007

Abstract
U.S. Department of Energy data suggest that previously discovered Oklahoma reservoirs contain approximately six billion stock tank barrels of mobile oil that will not be recovered using current production practices. This mobile oil should be recovered using current technology. A significant amount of this oil is believed to be in reservoirs deposited in fluvial-deltaic (FDD) environments. These FDD reservoirs have low recovery factors because they generally have substantial heterogeneity.
This paper presents results of nine case studies of Pennsylvanian FDD reservoirs. The case studies were part of the University of Oklahoma's U.S. DOE Class I project completed in 1997. The project was funded by the Department of Energy to determine if reservoir management and production strategies could be altered to increase expected recovery from the reservoirs. The FDD reservoirs studied were relatively small and thin. Some of them were associated with aquifers and had water drive. Because of the small reservoir sizes, most were developed with a limited number of wells. The largest reservoir studied had 36 wells. Expected primary recoveries for most of the reservoirs studied were less than 20%. Most wells were producing less than five barrels of oil per day at times of the studies.
The simulation studies reviewed in this paper combined available geological and engineering information to develop new geological models for the reservoir. The models were translated into input data files for black-oil reservoir simulators. The models were validated by matching past reservoir behavior. After the models were validated, alternate production strategies were investigated. The alternate strategies generally included an extrapolation of the current strategy (a base case), well completion changes, infill drilling, and water injection. In one case, gas injection was studied. The alternate strategies were compared with the base case. For almost all reservoirs, it appears that recovery could be fifty per cent larger than can be expected from the base case. One reservoir had an estimated recovery eight times larger than the current policy and for one reservoir it did not appear that any alternate exploitation strategy could increase recovery. The authors used commercial, ECLIPSE, and public domain, BOAST3, reservoir simulators in the simulation studies.
A New Stabilized Method for Use in IMPRES-Type Numerical Reservoir Simulators
Authors: Meijerink J.A. 
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.

Abstract
The stabilized IMPES technique for solving reservoir fluid flow equations allows larger timesteps and uses less calculation time than the standard IMPES method if stability control is the limiting factor. Otherwise it reduces to the standard IMPES method. This technique can easily be implemented in existing IMPES type simulators, and can be combined with both 1-point and 2-point upstream approximations If the stability problem is not too severe, it can easily compete with implicit simulators in computer time and storage.

Introduction
In simulators of the IMPES-type the nearly elliptic pressure equation is solved implicitly saturation equations, ranging between parabolic and hyperbolic, are solved explicitly. The explicit solution of the saturation equations dictates a maximum for the timestep to preserve stability and non-oscillatory behaviour. This maximum is regularly less than the limitations for control of the truncation error, especially if the mobility ratios are large and the fluid velocities are high in comparison with the pore volumes of the grid blocks.
In this paper we shall describe a time-discretisation method that allows a k2 times larger timestep for k times more calculations while the solution remains stable and/or non-oscillatory. When the truncation error is the limiting quantity, the method becomes equal to the commonly used forward-explicit time discretisation method.

THE STABILIZED EXPLICIT METHOD
For simplicity we shall restrict ourselves to a simplified linear partial differential equation for the saturation, given by:
dS(x,y,t) ————— = dt
d2S(x,y,t) d2S(s,y,t dS(x,y,t) dS(x,y,t) ————— + ————- - ————— - ————- dx2 dy2 dx dy
(1)
The boundary conditions are given by:
S(x,y,0) = 0
S(0,y,t) = 1
S(x,0,t) = 1 (2)
To solve this equation we use finite difference analogs. The continuous domain is replaced by an (n + 1) × (n + 1) equidistant grid system, with grid spacing h, central differences approximating the second-order spatial derivatives and 1-point upstream differences being used to approximate the first-order spatial derivatives. The latter can also be represented by two-point upstream differences.
In both cases this leads to a set of n2 ordinary differential equations given by:
ds -- = - As + g (3) dt
Fine Particulate Matter: How Dirty is Clean Combustion?
Authors: Christy Roger H. , Ziman Stephen D. 
Published: December 2007

Abstract
Changes in the Federal health-based ozone and fine particulate (PM2.5) standards will cause many regions of the United States to be declared "non-attainment." Attainment plans, which include emission control strategies, will be required by the year 2007. In late 1997, the U.S. Department of Energy began funding a study to determine real-time particulate matter concentrations from various combustion sources. Both the current Federal, and the more stringent California ozone standards have required significant emissions controls for ozone precursors such as nitrogen oxides and volatile hydrocarbons. One goal of the investigators was to determine if control technologies presently in place for meeting state and federal ozone requirements also minimize emissions of fine aerosols from combustion. A second goal was to provide new information about fine aerosol emissions from combustion sources, as the present information is old, and questionable. The study's selected technologies, reflecting the current state-of-the-art, could represent common controls when the new particulate standards take effect.
This paper will review the selection process of the various equipment, discuss the test methods used, and summarize the results. The selections included a rich-burn internal combustion engine with non-selective catalytic reduction, a steam generator with flue-gas recirculation, and two different sized turbines, both with water injection. Test methods included laser-induced breakdown spectroscopy (LIBS), laser aerosol spectroscopy (LAS), EPA Method 5, and a real-time particle-bound PAH monitor. Preliminary data indicates that the best emission controls for ozone precursors currently in place, along with the appropriate fuel selection, have exceptionally low PM2.5 levels, and would be expected to have insignificant impact on PM2.5 concentrations. Therefore, a need for additional fine particulate emission controls on these combustion sources is not anticipated.
Pipeline Management Program
Authors: Winkler William R. , Hesson Bruce H. , Shemaria Mark A. 
Published: December 2007

Abstract
Due to a spill from an unregulated pipeline in 1993 the legislature granted the Department of Conservation's Division of Oil, Gas, and Geothermal Resources (Division) jurisdiction over oil and gas production pipelines. As a result new pipeline regulations were promulgated in 1994 and 1998. The first regulations were broad construction standards and the second were a two tiered risk based system that included construction, maintenance, and testing requirements. Part of the regulation adoption process included statistics on oil spill frequency and clean-up cost estimates of between $15 and $25 million. Combining these statistics with a case study that demonstrates the potential reduction in the spill frequency clearly shows the benefit of initiating an integrated pipeline management plan. This is especially important in urban areas and environmentally sensitive areas when considering the potential for penalties imposed by any one of a number of regulatory agencies.
Role of Fracture Face and Formation Plugging in Injection Well Fracturing and Injectivity Decline
Authors: Saripalli K. Prasad , Bryant Steven L. , Sharma Mukul M. 
Published: December 2007

Abstract
Particle plugging of wells in the near wellbore region can have an important influence on the initiation and propagation of thermally and hydraulically induced fractures during water injection. Fracturing in turn can significantly influence the rate of injectivity decline in water injection wells. Development of models that elucidate the role of plugging of the fracture face and surrounding formation on the growth of fractures, and the resulting injectivity behavior, is an important research need. We present a model to predict the initiation and growth of a fracture in the near wellbore region due to the combined influence of injection pressure, changes in pore pressure, thermal stresses due to the injection of cold water, and an additional pressure drop due to particulate plugging. Fracture growth and fracture face plugging are modeled as dynamically coupled phenomena. The results indicate that wellbore plugging can significantly affect the initiation of a fracture. Further, plugging of the fracture face itself can have a major impact on the growth of the fracture, and the overall injectivity of the well. It is found that at a given injection rate, an increase in plugging leads to significant increases in fracture half-length. Results also demonstrate that a longer fracture does not necessarily imply an increase in injectivity, if there is significant permeability impairment due to plugging of the fracture face. The effectiveness of fracturing as a well-stimulation mechanism can be seriously diminished due to fracture face plugging in injection wells.
Shallow Water Flow Planning and Operations: Titan #1 Exploration Well, Deepwater Gulf of Mexico
Authors: Schuberth Paul C. , Walker Mike W. 
Published: December 2007

Abstract
Shallow water flows (SWF) from overpressured aquifers have been a persistent problem in the deepwater Gulf of Mexico (GOM) and can create significant financial and operational risks for exploration and development drilling programs. For the GOM, shallow water flow intervals typically occur between 300 ft to 2500 ft below mudline (BML) and in water depths greater than 1500 ft. If left unchecked, the disturbance from the water flow can cause loss of soil strength surrounding the wellbore, thereby compromising the structural integrity of the well. In industry, extreme cases have led to collapsed casing and/or total loss of wellbores.
The Titan No. 1 exploration well was drilled in Garden Banks Block 785 (GOM), in 4640 ft of water. At Titan, the planning and successful implementation of operational procedures designed to mitigate the risks associated with SWF hazards included: performing a shallow hazards assessment, preparing and implementing SWF contingency plans, identifying the SWF zone quickly, immediately controlling the water flow zone with weighted mud (while drilling riserless), and using nitrified foam cement to seal off the water flow behind 20" conductor pipe. Operations at Titan were based on the philosophy of quickly identifying the SWF, and immediately stopping the flow with weighted mud, as the chance of successfully mitigating the flow and maintaining the structural integrity of the wellbore will likely decrease with time if the sand is allowed to produce water, sand and/or sediment.
Problems of Ultra-Deepwater Drilling
Authors: Shaughnessy J. M. , Armagost W. K. , Herrmann R. P. , Cleaver M. A. 
Published: December 2007

Abstract
Ultra-deepwater drilling activity is at an all time high. Recently, there were only two rigs rated to, and actually working in, water depths greater than 6,000 ft. Soon there will be over twenty. This increase will involve new deepwater operators and bring a large number of new people to deepwater. This paper presents some of the problems that have occurred in deepwater operations under the assumption that an understanding of what can go wrong is the best way to avoid problems. It will identify these problems and discuss the critical topics of rig positioning, environmental considerations, BOP control, riser management, well control, wellbore construction, production problems, and personnel training and safety.
Drilling Performance Guidelines - A Tool for Sharing Drilling-Related Knowledge and Experience
Authors: Curry D. A. , Singelstad A. V. , Bowden D. 
Published: December 2007

Abstract
A major operator and a service company have collaborated to produce an on-line knowledge base, with the objective of helping their personnel achieve consistent good drilling performance.
The knowledge base is a highly structured electronic manual which provides a tool for drilling engineers to use in day-to-day operational work, a training aid for new engineers, and a one-stop reference source for drilling engineers, geologists and petroleum technology workers. It is a "living document", updated to reflect advances in technology and understanding.
This paper describes the knowledge base content, structure and mode of use, demonstrates its advantages over a conventional paper manual, and shows it to be a powerful tool for capturing and sharing drilling performance-related knowledge and experience.
Compression of Downhole Data
Authors: Bernasconi G. , Rampa V. , Abramo F. , Bertelli L. 
Published: December 2007

Abstract
Measurement-While-Drilling (MWD) services efficiently support drilling decisions, therefore these tools are becoming a de-facto standard on well sites. Currently, the main drawback of MWD equipment is the absence of a high bit-rate telemetry system to enable real-time activities. This problem may be solved by employing either an off-line solution, with limited memory capacity up to few hundreds of Mbytes; or an on-line solution with telemetry at a very low bit-rate (tens of bits/sec). However, following the off-line approach with standard acquisition parameters, the internal storage memory would be filled up in just a few hours at high acquisition rates. On the contrary, with the on-line solution only a small portion of the acquired signals (or only alarm information about potentially dangerous events) can be transmitted in real-time to the surface by using mud-pulse telemetry. In this paper, we present a lossy data compression algorithm based on the wavelet transform (WT), which is suitable for downhole implementation and may be successfully applied to both on-line and off-line solutions. Numerical tests based on real field data achieve compression ratios up to 15:1 without noticeable signal degradation. This allows a significant increase in downhole time acquisition and in real-time information that can be transmitted through mud-pulse telemetry.
Drilling and Completion of Horizontal Wells Requiring Sand Control
Authors: Burton Bob , Hodge Richard 
Published: December 2007

Abstract
Horizontal wells are often used to increase production rates and improve recovery. The increased inflow area and ability to penetrate/drain multiple targets make horizontal wells a cost-effective producing strategy in many oil and gas developments. However, analysis of horizontal wells requiring sand control indicates that many wells completed with sand control screens suffer from poor inflow performance. Previous studies have shown that screen plugging by residual Drill-in Fluid filtercake can lead to severe flow impairment. To minimize the potential for screen plugging, various drilling and completion practices have been tried with varying success.
This paper discusses well damage mechanisms, investigating the impact of the magnitude of different types of damage on well inflow performance. Critical damage mechanisms are highlighted and methods of preventing or remediating damage are discussed. The results of laboratory testing of Drill-in Fluids and cleanup/remedial treatments are compared to field case histories to illustrate the importance of Drill-in Fluid maintenance, treating fluid composition, and treating fluid placement.
Consequences and Relevance of Drillstring Vibration on Wellbore Stability
Authors: Santos Helio , Plácido J. C. R. , Wolter Claudio 
Published: December 2007

Abstract
Historically, wellbore instability problems have been mainly attributed to the physico-chemical interaction between the rock and the drilling fluid, especially when this is a water-based fluid (WBM). However, recent studies have shown that these chemical effects may be irrelevant in comparison with other energetic events which are present during the drilling operation of a well. Excessive drillstring vibration has been identified as such an event that can cause a great amount of damage to the wellbore. Although some studies present clear indications that the reduction of drillstring vibration has led, in many occasions, to an improvement on instability problems, still today this item only deserves attention from equipment divisions, aiming at reducing drillstring fatigue problems.
The main objective of this paper is to show the clear existing relation between excessive drillstring vibrations and serious well instability problems. It is shown, in energetic terms, that drillstring vibration, when having enough lateral amplitude to hit the wall, is responsible for irreparable damage to the borehole. Simple ways of quantifying vibration effects in terms of energy are presented. The paper also presents field measurement data, obtained with surface vibration sensors, which clearly allow identification and correlation between vibration problems and wellbore instability, through the comparison of these vibration records with caliper logs.
Underbalanced Drilling Gains Acceptance in Europe and the International Arena
Authors: Gedge Ben 
Published: December 2007

Abstract
Underbalanced Drilling is the natural and inevitable technological progression of horizontal drilling developed in the United States Austin Chalk formation, primarily for field re-development and now extended to new reservoirs where impairment is a key issue.
Horizontal drilling greatly improved recovery and productivity rates, particularly in redevelopment of existing and often pressure depleted reservoirs, but still encountered many of the drilling problems associated with conventional directionally drilled wells. In the case of mud losses, impairment and formation damage, the problems increased due to the wellbore being open for much longer and of course having much greater length through the reservoir section. Operators around the world quickly saw the advantages of horizontal drilling, which rapidly became a standard field development technique, onshore and offshore where the geology and reservoir were compatible with this method of development. The same now applies to underbalanced drilling. The advantages are quickly being seen and the technology employed where the geology and reservoir are suitable.
The majority of hydrocarbons being exploited today are found in existing fields or in complex and lower quality reservoirs. This is where underbalanced drilling technology can improve recovery and in some cases reduce development costs.
High Strength Sour Service C110 Casing
Authors: Urband-P.E Bruce E. , Morey Steve 
Published: December 2007

ABSTRACT
Drilling high pressure, high temperature (HP-HT) wells over the last several years has brought forth and accentuated the need for higher strength OCTG (Oil Country Tubular Goods) grades which are suitable for use in sour gas environments.1, 2 Drilling engineers are designing casing strings at depths where higher strength is needed. The presence of hydrogen sulfide has traditionally restricted the use of casing grades with minimum yield strengths from 90 to 95 KSI (API Grades C90 and T95). Recent advances in metallurgy and pipe making now enable the drilling engineer to utilize high strength, sour service (HSSS) tubular grades with minimum yield strengths from 100-110 KSI (C100, C105 and C110).
This paper discusses the metallurgical attributes of high strength, sour service (HSSS), tubular goods and provides information about specific cases where without HSSS grades successful, economic completions would not be possible. The paper also discusses the manufacturing techniques and material properties necessary to assure that casing products are suitable for use in sour environments at high pressures. A brief history and description of many of the API casing and tubing grades are discussed relative to their properties and intent for sour service applications. Details of the testing necessary to assure proper serviceability when exposed to hydrogen sulfide (H2S) are provided. Specialized testing, which the National Association of Corrosion Engineers (NACE) has standardized for oil and gas production equipment will also be discussed. Information is provided on both casing and coupling stock with thickness’ that have been traditionally difficult to assure the metallurgical uniformity and resistance to hydrogen sulfide stress cracking (SSC).