bluuebunny/crossref_metadata_2025_split huggingface dataset:
Petroleum Producer Risk Profile Analysis: Does Risk-Taking Pay
Authors: Virine Lev 
Published: February 2011

Abstract
Petroleum producers have different tolerance towards risks. When some predominately junior producers focus on exploration, development, and production in plays with higher risks, others often curtail exploration and development in time of economic uncertainties or tend to focus on the developed plays. Producer's attitude towards risks should be consistent with corporate strategy. Decisions regarding different exploration, development, and production projects should be made based on consistent assessment of risk attitude. The challenge is to elicit company's preferences towards risks and apply this information to the corporate decisionmaking. This paper describes methodology of the risk attitude analysis for the petroleum produces. In order to numerically assess producer's attitude towards risks a mathematical model has been developed. The model employed a number of key performance indicators tailored to assess risk attitude. Different weights were assigned to each indicator. Composite risk attitude score for each producer was calculated based on key performance indicators. This score represents producer's risk attitude and can be used in decision tree analysis as well as in multi-attribute utility analysis. The proposed methodology was applied for the comparison of risk attitude of different independent gas producers operating in North America. The positive correlation between risk taking and company's performance can be demonstrated under certain conditions, such as access to financing and technology. The proposed methodology can be applied to eliciting of risk attitude of the petroleum producers for the purpose of improving corporate planning process.
Quantitative Ranking Measures Oil Field Chemicals Environmental Impact
Authors: Jordan Andy , Daulton Dan , Ann Cobb Jo , Grumbles Thomas 
Published: February 2011

Abstract
Environmental stewardship has been and continues to be a critical component of the oil and gas industry, as exploitation of shale and other unconventional gas reservoirs requires large volumes of water for economic and efficient production. Evaluating and communicating the hazards of chemicals is done in a highly variable manner across the world. However the recent adoption of the Globally Harmonized System of Classification and Labeling of Chemicals (GHS) by multiple Global regulatory bodies has brought international consensus to hazard criteria and definitions. This system is being implemented with REACH in the EU. In the US OSHA has just proposed the GHS criteria as the basis for modifying their hazard communication regulations. This standardization ensures information about hazards and toxicity of chemicals is more universally available, to enhance protection of human health and the environment during handling, transportation and use. It is this scheme that we are beginning to utilize as the basis for the ranking of products and systems.
This paper will describe the evaluation and implementation of a practical and quantitative process of ranking well servicing products based on their safety, health and environmental impacts. The ranking allows operators to select and use products that best fit their environmental stewardship goals, and provides scientifically sound tools for better research and development, and educational efforts.
Successful Thermal Recovery of Heavy Oil From an Ultra Tight Reservoir Renews Development of the 100-Year-Old Orcutt Oil Field
Authors: Elias R. , Wilson M. , Vassilellis G. D. , Bust Vivian 
Published: February 2011

Abstract
This paper discusses a pilot project for exploiting the shallow oil-saturated diatomite located on the Careaga Lease in the Orcutt Oil Field, Santa Barbara County, California. The project is one of two successful new operations underway in the Central Coast of California that show oil production by cyclic steam stimulation of oil-saturated diatomite is possible. This method of oil production has been a success in the San Joaquin Valley since around 1996. It is now extended to a similar accumulation located over 100 miles away.
This case study chronicles the encouraging production response from a similar virtually unexploited zone known for over 100 years. Under full development, expected production could exceed historical peak levels from a resource many considered too shallow and too tight to exploit. Modern techniques are considered vital to making the Orcutt diatomite productive and successful.
The Orcutt oil field is located south of the town of Santa Maria, in Santa Barbara County, California. Discovered in 1901, it was first called the &#34;Santa Maria Field&#34; until the larger Santa Maria Valley oil field was discovered in the mid- 1930&apos;s. The name was changed to the Orcutt oil field. Cumulative oil production is in excess of 181 million barrels. Daily oil production is at a 25-year high. It is the largest onshore producing field in Santa Barbara County.
Tight Gas Well-Performance Evaluation With Neural Network Analysis for Hydraulic Propped Fracture Treatment Optimization
Authors: Huckabee Paul , Jin Minquan , Lund Robert , Nasse Dave , Williams Kristin 
Published: February 2011

Abstract
This paper summarizes the application of data mining techniques and neural network multi-variable analysis to evaluate critical parameters impacting well performance and optimize hydraulic fracture treatment design for tight gas well completions in the Pinedale Anticline field in western Wyoming. Challenges and uncertainty associated with single variable analysis are discussed with consideration of the complexity of reservoir parameter variability and nonsequential coincident completion variable modifications. Neural network model development is summarized with emphasis on applications for well performance evaluation and hydraulic fracture treatment optimization. Results are presented from extensive trials performed during 2009 development activity at Pinedale.
Don't Let It Weigh You Down: How To Benefit From Anchoring
Authors: Welsh M. B. , Begg S. H. 
Published: February 2011

Abstract
Anchoring describes the tendency for people's estimates of unknown quantities to be affected by numbers (or information) they have recently seen (or vividly remember). In the oil & gas industry, anchoring is regarded as a potential problem resulting from, for example, the sparsity of data that leads to the common practice of using analogues. "Base Case" or "Reference Case" models can also act as anchors. Much of the anchoring research, however, ignores the question of what estimates look like in the absence of anchoring values. Here we discuss previous research on anchoring and examine the conditions under which anchoring provides a benefit to decision making and whether these occur within the oil industry. We present the results of three studies, the first showing that, while anchoring results in greater deviations from the true value on average, it can also restrict the range of estimates so as to actually reduce the expected error in any single estimate.
The second study follows up on recent research showing benefits from elicitation techniques that cause a decision maker to repeatedly probe their knowledge. Thus, it tests the hypothesis that a decision maker who has seen multiple anchors may produce better estimates. Finally, in study 3, we demonstrate that people with greater knowledge are, in fact, less susceptible to anchors.
We conclude that, while anchoring can cause significant bias in estimates, the judicious use of anchoring values will not necessarily result in worse estimates. Instead, we identify circumstances where providing one or more anchoring values can produce a net benefit in terms of accuracy. Given the use of analogues and "bases cases" within the industry, understanding how anchors affect estimates is essential to improving estimates. This paper demonstrates that anchoring need not always be regarded as a bias to be overcome - rather, sometimes it is a tool that can be used to improve estimates.
Advances in Cased-Hole Compressional and Shear Sonic Acquisition and Processing
Authors: Murray Doug , Endo Takeshi , Sunaga Shin’ichi , Yan Hua Li , Voskamp Arne , Desport Olivier 
Published: February 2011

Abstract
The acquisition of high-quality borehole sonic formation slowness data in cased-hole environments is dependent on cement bond quality. It has generally been considered that when cement bond is poor, cased-hole sonic slowness data quality will also be poor. Additionally, in fast formations, when cement bond is good, casing arrivals can interfere with formation compressional arrivals, and in slow formations the acquisition of high-quality cased-hole dipole shear slowness data can be problematic.
The advent of the latest sonic acquisition technology and related interpretation techniques has reduced these formidable challenges. More powerful sonic transmitters, improved receivers, altered transmitter-receiver spacings, and fundamental changes in tool design have meaningfully improved the acoustic signal-to-noise ratio. An improved understanding of cased-hole borehole acoustic modes, the ability to transmit acoustic energies at more optimal frequencies, and the capability to simultaneously acquire cement bond log information have all contributed to improved cased-hole sonic slowness logs.
With the latest technology, accurate formation compressional slownesses can now be extracted in previously problematic cased-hole environments that contained either poor cement bond or fast formation slownesses near to the casing arrival. Additionally, dramatic improvements are evident in formation shear slowness acquisition in very slow formations where previous cased-hole technology had been unsuccessful.
These developments have a profound impact on drilling operations, seismic velocity modeling, geomechanics, and reservoir characterization. In existing cased wells, the latest sonic technology presents a viable option to acquire critical compressional and shear slowness information. In newly drilled wells, the feasibility of acquiring accurate cased-hole slowness information can reduce the necessity and the inherent risk of an openhole logging run.
The Maturity of Organic-Rich Shales Using Microimpedance Analysis
Authors: Kenechukwu C. , Prasad Manika , Batzle Michael L. 
Published: February 2011

Abstract
The increasing importance of organic-rich shales, ORS as hydrocarbon reservoir rocks has lead to a demand for better understanding of the processes that lead to shale maturity. An improved understanding of these processes in the laboratory can lead to development of methods for their indirect geophysical detection at in-situ conditions. Present day methods for maturity detection by geochemical means is limited by spatial density of sampled wells and sample availability. The study of maturity relationships with rock physical properties and microstructure can lead to methods for indirect detection by establishing correlations between rock character, kerogen content and maturity. This would allow for improved project economics in exploration and development of shale oil fields.
In this paper we show how micro-impedance can be used to understand textural and anisotropic relationships with maturity. Microscale anisotropy increases with kerogen content, a measure of organic matter. This observation is supported by published reports of studies made at the core (centimeter) scale. Mineralogy also contributes to anisotropy; clay-rich shales have higher anisotropy, while silica-rich shales appear more isotropic. The Young's modulus of kerogen is shown to increase linearly as kerogen matures. Our findings could serve as considerations for improving petrophysical models aimed at indirect and in-situ detection of maturity.
Sea Water Injection Mobile System (SWIMS) for Waterflooding Marginal Offshore Oil Reservoirs: A Case Study From Tantawan Field, Gulf of Thailand
Authors: Rexilius J. P. , Sahni A. 
Published: February 2011

Abstract
Seawater Injection Mobile System (SWIMS) is a novel concept involving the use of portable equipment (high pressure pumps, tanks, filters and hoses) to take seawater from the ocean, treat it with anti-corrosion and anti-bacteria chemicals, pump it at high pressure's into a well at surface, and subsequently waterflood subsurface oil reservoirs.
SWIMS is designed to unlock significant waterflood reserves distributed over small reservoirs across several offshore platforms in an oil field. The system is modular, flexible and mobile; attributes that help get water in the ground quickly and cheaply, resulting in incremental waterflood reserves from marginal offshore oil reservoirs.
The concept works best in small, high permeability, homogenous reservoirs and in a favorable mobility ratio environment. In such a scenario, water can be injected at rates significantly higher than off-take rates while still maintaining stable displacement. This allows for quick waterflood processing of small reservoirs and SWIMS can be de-mobilized and rigged up on another platform to repeat injection.
The SWIMS system allows implementation of waterflood projects on platforms which do not warrant the laying of a produced water pipeline and installation of injection facilities offshore. This low cost and flexible system thus enables recovery from small offshore oil reservoirs that would usually not be subjected to waterflooding due to economic constraints.
The SWIMS concept was trialed on an offshore platform in Tantawan Field, Gulf of Thailand (GoT) in January 2010. Post-drill subsurface characterization studies revealed a waterflood opportunity in a small oil reservoir penetrated by 3 wells. Best practice geological correlating, RFT pressure data collection and interpretation, and a successful interference/pulse test were used to confirm reservoir connectivity prior to execution of the marginal waterflood. Waterflood response was observed soon after start-up of injection, with a pronounced increase in oil rate and pressure, together with a reduction in gas-oil ratio at a voidage replacement ratio of between 1.5-2.
This paper will outline the details of SWIMS including the equipment utilized, fit-for-purpose chemical treatment and corrosion monitoring programs, as well as other key attributes of the unique system. The subsurface characterization work leading to the identification of the pilot waterflood in Tantanwan field will also be discussed along with production results and waterflood evaluation of this successful application of SWIMS in the Gulf of Thailand.
Next Generation Multi-Stage Completion Technology and Risk Sharing Accelerates Development of the Bakken Play
Authors: Houston Matt , McCallister Mark , Jany Josh , Audet Josh 
Published: February 2011

Abstract
Over the last decade, an industry wide shift to unconventional plays has occurred due to advanced drilling and completion technologies allowing the recovery of previously uneconomic reserves. A notable play in this category is the Bakken formation in the Williston Basin. Through the application of horizontal drilling and innovative completion design, the recoverable reserves in the Bakken are now estimated at 3.65 billion bbl of oil.
Through multiple case study wells and direct offset comparisons, this paper analyzes production results for two completion methods employed in the Bakken today: cemented production liners with "plug and perf" stimulation and open hole, multi-stage system completions. Additionally, production differences based on stage number, stage interval length, and 640 acre spacing versus 1,280 acre well spacing are presented.
The trend to increase stage density in extended-reach, horizontal wells in the Bakken requires leading-edge technology to maintain operational efficiencies and improve overall well economics. With the introduction of new "high density" technology to open hole, multi-stage systems, these requirements are exceeded with maximum stage density capability allowing for decreased completion time and lower-risk stimulation practices compared to conventional methods.
Capacity and Constraints for Carbon Dioxide Sequestration in Aquifers and Depleted Oil/Gas Reservoirs in Carbonate Environment
Authors: Gupta Anuj 
Published: February 2011

AbstractProduction of oil/gas to meet the increasing energy needs results in generation of significant amount of CO2. This study presents results of experimental and simulation work to understand opportunities and challenges in sequestering CO2 in carbonate rocks typical of aquifers and oil/gas reservoirs in the Middle East. CO2 corefloods were conducted in samples from carbonate analog outcrops to simulate sequestration process, and, changes in the pore-space due to dissolution/precipitation were quantified by time lapse CTscans and measurement of relative permeabilities. Density and compressibility of CO2 and Solubility in reservoir brines was measured to calibrate predictive models and used in simulation studies.Objective is to reliably calculate sequestration capacity available in aquifers and depleted reservoir in a region, and to evaluate the long-term stability of seals in such systems. Experimental results facilitate reliable simulation studies which are very important for determining how much CO2 can be sequestrated. Such studies also lead to understanding of potential leaks due to interaction of CO2 with carbonate minerals of sealing formations.Density and compressibility measurements of CO2 are reported at up to 5000 psia and 250 F. The results show good agreements with available predictive models and were used to calibrate parameters in such models. CT-scans and petrophysical properties of core samples show dissolution in some pores but precipitation in other pores of carbonate matrix. Simulation study reports ranges for storage capacity in tones/acreft.The results of this study are directly applicable for evaluating CO2 sequestration opportunities in Qatar, Middle-East since the outcrop samples studied are analog for Arab and Khuff Formations, which hold most of the petroleum reserves in the Middle-East. CO2 properties and its interaction with carbonate matrix are significant for CO2 sequestration study anywhere.
Effect of Dispersant on Asphaltene Suspension Dynamics: Aggregation and Sedimentation
Authors: Hashmi Sara M. , Firoozabadi Abbas 
Published: February 2011

Abstract
When oil is mixed with light alkanes, asphaltenes can precipitate out of oil solutions in a multistep process that involves the formation of nano- and colloidal scale particles, the aggregation of asphaltene colloids, and their eventual sedimentation. Amphiphilic dispersants can greatly affect this process. The mechanism of the dispersant action in colloidal asphaltene suspensions in heptane has been shown through previous work to be due in part to a reduction in the size of the colloidal asphaltene particles with the addition of dispersant. However, previous studies of the sedimentation behavior have also revealed evidence of aggregation processes in the colloidal asphaltenes in heptane that has yet to be investigated fully. We investigate the effect of dispersants on this aggregation behavior through the use of dynamic light scattering, showing that both the amount of dispersant as well as the amount of heptane dilution can affect the onset and extent of aggregation in colloidal asphaltene suspensions. The light scattering results match well with those obtained through the macroscopic sedimentation experiments.
Continuous Wellbore Surveying While Drilling Utilizing MEMS Gyroscopes Based on Kalman Filtering
Authors: ElGizawy Mahmoud , Noureldin Aboelmagd , El-Sheimy Naser 
Published: February 2011

Abstract
The current method to compute the wellbore while drilling is based on stationary surveys at the desired station. This is done by measuring the inclination and the azimuth of the borehole between the current and the previously surveyed stations. Using a mathematical model based on assumptions of the shape of the drilled section, the coordinates of the borehole can be derived. This current method neglects the actual trajectory between the two surveying stations.
Exploration and production companies demand cost effective drilling operations. Thus, demand has been rising for a continuous survey that captures the actual trajectory between the stationary surveying stations. This provides an actual estimate of the curvature "dogleg" along the well trajectory. In addition, this allows a better estimation of the casing and cementing of the borehole. Therefore, in this development the wellbore trajectory between the two surveying stations is continuously surveyed using three accelerometers and three MEMS gyroscopes. The computation algorithm is based on strap down Inertial Navigation System mechanization and Kalman filtering.
The inputs to the continuous drilling survey system are the accelerometers and gyroscopes measurements, while the outputs are position, tool face, inclination and azimuth of the drill bit. This wellbore survey system will exhibit an unlimited growth of position, and azimuth errors if there are no external observations to update the surveying system. Two external update schemes can limit this error growth while drilling. The first is based on the continuous source of drilled pipe length measurements while the second is the zero velocity update. The Kalman filter continuous surveying system was successfully applied to drilling tests. External updates of the drill pipe length were utilized to reduce measurement error drift. When the drilling process was stopped to connect new drill pipe stands, zero velocity updates were employed by the Kalman filter.
Numerical Model for Interpretation of Distributed Temperature Sensor Data During Hydraulic Fracturing
Authors: Seth Gaurav , Reynolds Albert C. , Mahadevan Jagan 
Published: February 2011

Abstract
Injection of cold fluids into tight gas formation during hydraulic fracturing results in cooling of the formation around the fracture and the wellbore. Fluid leakoff from the fracture causes a non-uniform temperature distribution around the fractured zone. Subsequently, during the shut-in period, the near fracture region warms up due to heat flux from the external reservoir rock. Thus, the near wellbore region is subjected to cooling and then warm back which can be measured by the use of distributed temperature sensors (DTS). In this study we develop a numerical model to calculate the temperature during both hydraulic fracturing and the shut in period.
The numerical model solutions can be used to interpret field data from the DTS during hydraulic fracturing, to estimate the fracture length, and when coupled with a wellbore model, to quantify the total volume of fracturing fluid injected into an interval. Additionally, the model developed can be used in a temperature history matching algorithm to obtain characteristics of the hydraulic fracture. The models are validated using analytical limiting case solutions.