bluuebunny/crossref_metadata_2025_split huggingface dataset:
Pressure Transient Model Characterization of Sealing and Partially Communicating Strike-Slip Faults
Authors: Charles D. D. , Rieke H. H. , Pal S. 
Published: December 2007

Abstract
Strike-slip faults are prevalent in petroleum reservoir accumulations. Understanding of flow dynamics of sealing and non-sealing strike-slip faults is necessary for offshore producing companies to evaluate the number of wells required to efficiently drain a given hydrocarbon reservoir.
A comprehensive pressure transient model characterization study of sealing and partially communicating strike-slip faults was conducted using a commercially available welltest software package. Emphasis was on the use of the log-log pressure derivative (LPD) as the key diagnostic tool, considering that the LPD is, perhaps, the most widely used welltest interpretation technique.
The research problem was reduced to running numerous numerical simulations on several strike-slip fault configurations that studied three key variables, such as the magnitude of the strike-slip displacement, the degree of leakiness of the fault and the position of the wellbore relative to the leaky fault.
Our results demonstrate that all three key variables affect the resulting LPD and the LPD can be complex, which in the absence of adequate understanding of reservoir geology could lead to misdiagnosis or erroneous reservoir behavior inference. It appears that buildup data interpretation is more severely affected than drawdown data interpretation.
Quantitative analysis of the data, assuming no prior knowledge of the presence of a leaky fault, indicate reasonable estimate of formation capacity and total skin factor, but estimate of reservoir boundaries or size can suffer, depending on the level of the three factors considered.
You Cannot Be Ethical if You Do Not Know the Rules
Authors: Merryman A. 
Published: December 2007

Abstract
A supervisor is comparing a projection prepared following traditional department procedures to a significantly higher projection from a computer model. The traditional procedures include structure maps and isopach maps of net pay. The isopach maps incorporate "cut-offs" for porosity, water saturation, and shale; and recognize reservoir boundaries based on lease lines. The computer model was constructed by using available data for input and allowing the computer to predict recovery without artificial "cut-offs" and without an intermediate step to construct maps.
Before trying to select the "right" projection, the supervisor will want to review the rules. Rules from academic training might help validate each projection and perhaps resolve some of the differences. Rules based on experience and judgment might help. Finally, reflection on the purpose of the report, the intended use, and the intended audience will reveal other rules. For instance, projections to support development on a concession outside the United States should follow the rules of the host country and the terms of the concession agreement.
This paper is the result of discussion with friends that led to a survey of engineers working in producing companies, consulting firms, and universities. The most common responses suggested management can do a better job of disseminating and enforcing the rules.
This paper will demonstrate that many rules are involved, some will conflict with others, and some will change. Reflection on the rules reminds managers that there is a purpose for every evaluation, and potentially, a different "right" answer for each purpose. Only by disseminating and enforcing the rules can management know that ethical decisions are being made, based on projections of evaluation engineers.
Restoring Investor Confidence Through Improved Reserves Estimation and Reporting
Authors: Hodgin J. E. , Harrell D. R. 
Published: December 2007

Abstract
This paper contains observations, suggestions and recommendations from the perspective of an international reserves consultant on improving the reserves estimation and reporting process within publicly-owned oil and gas producers. Specifically addressed are the establishment and oversight of (1) an internal network of qualified reserves estimators having access to a secure database (2) an internal reserves audit team to ensure consistency, independence and compliance (SEC/ASC/Others) and (3) provision (if applicable) for ensuring efficient reserves verification by one or more independent third parties. Also addressed are several levels of third-party reserves authentication measures ranging from the design of internal processes through complete "grass roots" reserves determinations. These recommendations arise from experience gained through consulting assignments with more than 50 companies reporting reserves to the US SEC and other regulatory agencies as well as process controls and transparency standards arising from the Sarbanes-Oxley Act of 2002. The ultimate beneficiary of improved estimation, verification and reporting is the investor.
Casing Drilling vs. Liner Drilling: Critical Analysis of an Operation in the Gulf of Mexico
Authors: Steppe R. J. , Clark L. , Johns R. 
Published: December 2007

Abstract
Increasingly, operators are looking for simple and effective methods to overcome the hazards and limitations imposed by depleted reservoirs, rubble zones or thief zones. One method is to utilize casing or liner drilling to isolate the problem area by combining drilling and casing in one operation. This can take on many forms from simple drill-in systems to full retrievable directional BHA's connected below the casing or liner string.
A major independent operator has recently drilled two 12-1/4" hole sections in different wells to isolate a problem thief zone (Well A-2 BP01 and A-3). The drilling of one of these sections with liner (A-2 BP01)1 and the other with casing (A-produced many operational and equipment learning that will increase efficiency in future applications. To drill the problem interval of the A3 well, the operator chose a tried and proven Casing Drive System, together with a new PDC casing bit2 to drill down a full string of 9-5/8" casing.
The choice of drilling with liner or casing is examined along with the equipment and operational practices required. Comparisons will be drawn with the offset well which was drilled conventionally and led to mud losses of over 3,000 barrels, the effectiveness of a smear or plastering effect while drilling with liner and casing is investigated.
A Strategic Gasfield Development Case in Sandstones Using Seismic Amplitudes and Dynamic Reservoir Characterization
Authors: Arévalo-Villagrán J. A. , Cinco-Ley H. , Samaniego-Verduzco F. , Martínez-Romero N. 
Published: December 2007

Abstract
The objective of this paper is to present a process for improving the planning of gas field development. We discuss how seismic amplitudes and dynamic characterization can be combined to optimize gas field development. The main concepts, methodologies, and tool used, as well as results obtained are shown for an actual Mexican gas field. A series of amplitude seismic maps were constructed by using 3D seiesmic interpretation. These maps were the essential part for detecting significant volumes of gas in place. Afterwards, calibrations of these maps with production data used in reserve evaluation studies resulted in a low risk development strategy for the field. The gas field example is comprised of three producing sandstones at different depths (E, G, and M), and has 14 producing wells. Hydraulic communication and the drainage areas for each reservoir, in both E and M sandstones, were evaluated through a combination of the amplitude in the seismic anomalies and production data analysis. A good agreement between the seismic amplitude and dynamic characterization of the pressure and production data was obtained, which improved the evaluation of the reservoir quality and the estimation of drainage area, original gas in place, and proved reserves. In E and M sandstones, four and three independent reservoirs have been detected, respectively. The E sandstone has an estimated value of 62 Bscf of original gas in place and the M sandstone has an estimated value of 110 Bscf of original gas in place. By using the reservoir dynamic model in combination with information of logs, cores, and production data, the economic optimum strategy for the field development was designed, that included the drilling of wells in areas with the best seismic amplitude.
Benchmarking Heterogeneity of Simulation Models
Authors: Sahni A. , Dehghani K. , Prieditis J. 
Published: December 2007

Abstract
This paper presents a workflow for benchmarking reservoir model heterogeneity with classical heterogeneity indicators. The advent of parallel simulation with multi-processors has resulted in the building of super giant geo-statistical earth models, which are subsequently up-scaled for simulation. Prior to running predictions, the models may be history matched or calibrated against available rate/pressure data by altering model properties like permeability, porosity, saturation, compressibility etc. But does the end product have the desired heterogeneity to adequately model a displacement process?
Ideally, one would like to have several models with varying heterogeneity levels that all honor the historical data. We describe a methodology for obtaining a desired heterogeneity level in the up-scaled and history matched simulation model. The desired heterogeneity level could be related to observed production log, core and pulse test data and also with analogs. The workflow described in this paper shows how a history matched simulation model (where primary production history is matched) could be used to predict displacement performance at any desired heterogeneity level, as described by a classical heterogeneity indicator like the Dykstra Parsons coefficient.
Fracture Skin: A Primary Cause of Stimulation Ineffectiveness in Gas Wells
Authors: Cramer D. D. 
Published: December 2007

Abstract
Fracture skin is a flow impediment that can exist in two distinct forms (Cinco-Ley and Samaniego-V.) The form considered in this paper is fluid loss damage (SFS). It can occur when capillary pressure exceeds drawdown pressure (i.e., initial or average reservoir pressure minus pressure in the fracture) and there is an excess of water in the system. Imbibing water can then cause a stable increase in water saturation, often dramatically reducing the relative permeability to gas in the area of the reservoir immediately adjacent to the hydraulic fracture faces. SFS is a function of fracture half-length (xF), damage-zone width (bS) and the ratio of k (undamaged permeability) to kS (permeability in the damage zone.) It results in a measurable pressure drop in the immediate vicinity of the fracture but not within the fracture itself. Yet the extra pressure drop near the fracture serves to make the fracture appear shorter or less conductive than it is physically and can dramatically reduce well productivity.
This paper is an in-depth study of the existence and consequences of the fluid loss damage form of fracture skin. The focus is a hydraulically-fractured well completed in a low-permeability (i.e. k=0.03 md) gas sand. Drawdown analysis of 12 months of daily rate and pressure data was correlated with a pressure buildup test done at the end of this flow period. A downhole shut-in configuration significantly reduced the duration of wellbore storage during the buildup test, allowing detailed characterization of the fracture and surrounding reservoir rock. The derived SFS from pressure buildup analysis was found to be +3, much higher than evaluated in examples shown by Cinco-Ley and Samaniego-V. The analytic results were verified by numerical evaluation with a multi-cell compositional reservoir simulator. It was found that a moderate conductivity fracture (FCD=7) with a xF of 160 ft was connected to the wellbore, but over time a 70-fold reduction in permeability to gas occurred in a 4-5 ft zone surrounding the fracture (non-unique solution.) The extra pressure drop caused by this damage zone reduced the effectiveness of the fracture to a zero-skin equivalent xF of approximately 5 ft. It is shown that the fracture skin probably existed from the onset of production but intensified with late-time water influx from the wellbore to the fracture. Remedial measures are described and evaluated for effectiveness in reducing the skin and improving well productivity.
The Conundrum of Formation Evaluation in High-Angle/Horizontal Wells: Observations and Recommendations
Authors: Rendeiro C. , Passey Q. , Yin H. 
Published: December 2007

Abstract
Over the last two decades the process of drilling high-angle and horizontal (HA/HZ) wells has changed from cutting-edge to almost routine. While the industry has developed technologies to log and acquire data from these wells, it has not yet developed the technology to interpret the data quantitatively on a routine basis. Generally, hydrocarbon pore volume (HPV) is calculated from the height, porosity, and water saturation derived from logs in near-vertical wells. Case studies have shown that application of similar procedures in high-angle and horizontal wells can result in values significantly different than those calculated from near-vertical wells. As the apparent wellbore deviation angle increases, so increases the uncertainty in the log-derived properties. Using currently available technology, our observation is that in wells with a relative angle to the formation greater then 80°, HPV cannot be calculated from logs with the same confidence as from near-vertical wells. While historically this has not been a problem, the impact of increased uncertainty associated with the reliance on HA/HZ wells for reservoir assessment needs to be recognized and addressed.
Techniques for Extracting Reliable Density and Porosity Data From Cuttings
Authors: Siddiqui S. , Grader A. S. , Touati M. , Loermans A. M. , Funk J. J. 
Published: December 2007

Abstract
The collection of core samples from a reservoir is essential for its proper characterization. Core data play very important roles in the following: log calibration, well treatment and performance prediction, reservoir modeling and simulation, and production and development planning. Coring is time-consuming, expensive and risky. It is difficult, if not impossible, to retrieve whole cores from horizontal and maximum reservoir contact (MRC) wells — which form the bulk of wells being drilled at present. As an alternative to coring, the use of cuttings has been proposed by many, as cuttings are always available from wells. Aside from some loss, contamination and depth-uncertainty (typically within 10 ft), cuttings show strong potential to represent all the formations encountered during the drilling of a well.
This paper discusses the capabilities of various laboratory instruments to extract reliable density and porosity data from cuttings. The methodology used involves full characterization of a carbonate core plug using several laboratory tools followed by crushing the plug into cuttings of different mesh sizes. Samples of different mesh sizes were then scanned with a CT-scanner and bulk densities and porosities were calculated using advanced histogram-based analysis techniques. Results for individual cuttings sizes were compared against those for the whole plug. Additional data on the same cuttings were generated using micro-CT, Environmental Scanning Electron Microscope (ESEM), Nuclear Magnetic Resonance (NMR) spectrometer and APEX (Apparatus for Pore Examination) mercury porosimeter, which were also used for comparison. A set of procedures was developed for generating porosity data based on image processing of SEM and micro-CT generated images. The work helped establish the size of about 2.5 mm as the limit of detectability of medical-based CT-scanners to generate reliable density and porosity data from drilled cuttings. Comparison between the micro-CT and ESEM data showed the range of application for each tool in determining porosities from cuttings. Comparison between the pore size distributions generated by the NMR and APEX mercury porosity instruments and their visual comparisons with ESEM images provide important insights for the pore network modeling efforts.
Limitations of Using Urea as a Nitrogen Source in Biodegradation of Petroleum Wastes
Authors: Jin S. , Fallgren P. H. , Li M. 
Published: December 2007

Abstract
Nutrient addition is important to achieving the carbon/nitrogen balance and successful biodegradation of petroleum contaminants. Urea has been considered as a preferred nitrogen source in enhancing biodegradation, because of its high nitrogen content and availability. This study investigated urea in the biodegradation of petroleum-contaminated soils collected from an arid and sandy location in Egypt. Ammonium nitrate served as the nitrogen amendment control in this study. Biodegradation of petroleum-contaminated soils from Wyoming was monitored as a comparison. Performance of urea was poor in the enhancement of biodegradation of petroleum-impacted soil from the Egyptian site, in addition, urea demonstrates an adverse effect on the biodegradation rates. Results indicate that urea may inhibit the microorganisms involved in petroleum degradation. Data from this study suggest that the application of urea in the enhancement of biodegradation of petroleum compounds may not be applicable in geological areas or soils structures similar to those in this study.
Are Slick-Water Fracturing Applications Effective in the J-Sand Formation?
Authors: Shaefer M. 
Published: December 2007

Abstract
Since the early 1970s, fracturing fluid systems utilized in the J-Sand treatments in the Wattenberg field have ranged from poly emulsion to cross link gels with and without an inert gas phase (e.g. N2, CO2). Current treatments typically consist of large proppant volumes and crosslinked fluid volumes (e.g. 500,000 lbs and 7,000 barrels). Large treatment volumes results in large job costs for the well operators who have searched for ways to reduce treatment costs without sacrificing well production. Also in early 2000, large treatments were resulting in poorer productive J-Sand wells due to suspected pressure depletion. In 2002, one well operator in the Wattenberg field implemented an alternative method to stimulate the J-Sand: (1) substituting the slick water based fluid for the massive crosslinked gel based fluid and (2) reducing the proppant volume by as much as 4.5 fold. This strategy reduced job costs significantly without impacting ultimate gas recovery. At the end of 2002, the well operator completely switched over to the slick water treatments (SWT) for the J-Sand interval. By lowering the completion costs of a J-Sand well, many additional wells will be drilled that otherwise would not be economic.
In this paper, the production from eight J-Sand wells stimulated with SWT will be compared to the 15 offsetting wells stimulated with crosslinked gel treatments (CGT). Production analysis methods will be utilized to determine reservoir and fracture flow capacity (e.g. drainage area, kh, effective fracture half length) for the wells considered in this case study. Also, treatment pressure history matching will be performed for selected wells to evaluate the resultant fracture geometry of the different styles of treatments.
Relative Permeability Modifier Treatments on Gulf of Mexico Frac-Packed and Gravel-Packed Oil and Gas Wells
Authors: Pietrak M. J. , Stanley F. O. , Weber B. J. , Fontenot J. S. 
Published: December 2007

Abstract
Estimates of worldwide oilfield water production are as high as 300 to 400 million barrels of water per day (bwpd), while oil production is only 75 million barrels per day (bopd)1. Put in different terms: for every 1 bopd produced, our industry produces approximately 4 to 6 bwpd, and for many depleted areas of the world this oil-to-water ratio can be much higher, reaching up to 1:100. Excessive water production from oil and gas wells can cause serious reductions in well productivity and significantly increases operating expenses.
In an attempt to reduce the oil industry's dilemma related to water production, there has recently been an increased interest in water control treatments using relative permeability modifiers (RPM). A new and unique RPM polymer is yielding significant economic benefits by increasing hydrocarbon production from treated wells.
Generally, RPMs are designed to control water production from high permeability streaks or due to coning issues. The polymer adheres to formation rock exposing its hydrophilic (water-loving) side to the pore throats. The RPM restricts water movement through the pore throat by reducing the effective size of the throat in the presence of water and by increasing drag on formation water flowing through the reservoir matrix. Because it deforms in the presence of hydrocarbons, the RPM typically does not adversely effect oil or gas flow. The newly developed RPM (along with careful selection of well candidates, correct treatment design, and proper placement) is helping increase the success of RPM treatments.
This paper will discuss the application and economic benefits from using the new low-risk RPM polymer. Multi-well RPM matrix treatments were performed on offshore Gulf of Mexico (GoM) frac-packed and gravel-packed wells. One particular RPM treated gas well showed a significant decrease in water production, a five fold increase in gas production and double the amount of oil. Payout for the entire treatment was just 7 days.