bluuebunny/crossref_metadata_2025_split huggingface dataset:
Integrated Process Improves Production of the Almond Formation in the Wamsutter Field, Wyoming: A Low-Permeability Case Study of Five Years of Continuous Improvement in Well Performance
Authors: Mullen Mike , Dickerman Rich , Stabenau Jack , Dobson Martin , Ohlson Charles 
Published: December 2007

Abstract
Recommendations for stimulation optimization in mature fields often meet with opposition from operators who are wary of changes in the design of well completions. Often, inertia exists among personnel because they are comfortable doing things the way they have been doing them and because they want to avoid the potential risk of a new idea. A common set of concerns regarding low-permeability gas reservoirs is how much the changes will cost and whether or not they will result in adding new reserves. To answer these questions, the reservoir must first be studied and analyzed so that a reasonable prediction can be made regarding the maximum potential of the well. An effective approach is to form an integrated team made up of specialists from both the operating and service companies to gather and process comprehensive information. This information should include data from reservoir engineering, drilling, petrophysics, geology, stimulation design, and production and completion operations.
This team approach was applied to the low-permeability Lewis and Almond sands in the Wamsutter field in southwest Wyoming. A team began studying the reservoir in 1998 to better understand the problems that prevented the wells from producing at their maximum potential. The team was challenged with the following tasks: Determine whether or not the wells were already performing as well as they could.Establish a benchmark by which to measure the success of any changes.Identify the major causes of underperformance.Apply new technologies and techniques to overcome the causes of underperformance.High-grade pay based on log evaluation, individual zone testing, and production logging.Design stimulation treatments that maximize the net present value from the well.Document the effect of specific changes in completion practices.
At the outset, a benchmark of the 90-day average production rate was established based on existing results. As a result of this ongoing effort, the original benchmark has been exceeded by over 100% over the past five years. The average production for these wells has also increased more than 50%.
Smart Well Technology Applied to a Horizontal Subsea Well at Gullfaks Satellites
Authors: Netland Svein Oddvar , Haugen Vibeke , Samsonsen Bianc , Krogh Per Kr. 
Published: December 2007

Abstract
The Statfjord Formation (Fm.) in Gullfaks Sør (GF Sør) was discovered in 1978, and set in production in 1999 as part of the Gullfaks Satellite Development.
The STOOIP for the GF Sør Statfjord Fm. was estimated to 35 mill. Sm3 in the Plan for Development and Operations (PDO), with estimated recoverable reserves of 12.6 mill. Sm3 through an 8-slot subsea development and partial pressure support by gas injection. The start up of the first two wells showed that the production rate were lower than expected, due to severe lack of reservoir communication, hence influx rates were insufficient to maintain planned offtake rates of 1000-2000 Sm3/sd. The GF Sør Statfjord Fm. is a fluvial to shallow marine reservoir with large reservoir heterogeneities. There is also structural complexibility, which limits the reservoir communication. Further development of the Statfjord Fm. was therefore postponed after completion of the first two wells due to lack of reservoir understanding and need for a revised development strategy. The third well in the GF Sør Statfjord Fm. was drilled in 2001. The well experienced gas breakthrough after a short time. Based on the gained production experience the reserves were reduced from 12,6 mill Sm3 in the PDO to 3,0 mill Sm3 in the reservoir management plan.
The main focus for the GF Sør Statfjord Fm. since 2002 has been to qualify the use of smart well technology to increase the recovery. Since the production has been limited by reservoir heterogeneity and gas breakthrough, surface operated down hole inflow control and multilateral wells were identified as possible solutions for future wells.
This paper describes the solutions made for the fourth horizontal subsea well drilled in the GF Sør Statfjord Fm. late 2003, where a two zones surface controlled inflow device system (DIACS) was installed. The paper also addresses the need for cheaper well and drilling solution from floating drilling units, to maximize the number of drainage points in reservoirs with limited economical reserves.
Continuous Borehole Curvature Estimates While Drilling Based on Downhole Bending Moment Measurements
Authors: Heisig G. , Cavallaro G. , Jogi P. , Hood J. , Forstner I. 
Published: December 2007

Abstract
The paper shows that a downhole bending moment measurement combined with a simple mathematical model can provide a good estimate of the wellbore curvature, matching the results obtained from survey data analysis quite well. In addition, the bending moment measurement delivers wellbore curvature information at a much higher resolution than the standard Minimum Curvature method, which assumes a constant curvature between the survey stations.
The paper presents numerous examples of downhole bending moment data measured in deployments with both rotary steerable and steerable motor BHAs and compares the dogleg severity estimates from the bending moment data with the dogleg severity derived from the survey measurements. Accuracy and limitations of the measurement and the model predictions are discussed. The paper also introduces a new method of analyzing cyclic hole effects applying FFT techniques to the depth-based bending data.
Trinidad and Tobago: The Atlantic Basin (Deep Water) Challenge
Authors: Rajnauth Jerome , Hasley Vincent , Roberts Carolyn 
Published: December 2007

Abstract
Interest in Trinidad and Tobago&s deepwater Atlantic Basin spans more than twenty years. Geoscientists working in the area have been curious as to what lies beneath water depths in excess of 1,000 metres. In 1996 and onwards, the drill bit talked.
The primary source of data over the area was provided by 2D seismic shot over the area in 1980&s. After the 1996 "Deep Water" Bid Round, extensive 3D seismic data was acquired over the eastern Blocks (Blocks 25a, 25b, 26 and 27) along with cores and gravity and magnetic data. The outcome of all of this data collection was eight wells drilled to various depths, none finding hydrocarbons in commercial quantities.
The exploration campaign proved the existence of a working hydrocarbon system. It also confirmed the presence of reservoir, predominantly in the eastern portion of the area. A better understanding of shale diapirism and its effects on the hydrocarbon system was also gained.
One of the major pitfalls in the interpretation of this basin was its comparison with the Gulf of Mexico. A misunderstanding of the tectonic history and the influence of major plate boundary movement also contributed to some of the drilling problems encountered.
The main unanswered question for the area is whether or not there are viable commercial hydrocarbon accumulations. Future work should look at the influence of shale diapirs on sedimentation patterns, the location of the proto-Orinoco as a sediment source, and the role of the tectonic setting of the area.
Injection Well Stimulation: Putting Away More for Less in California Waterfloods
Authors: McClatchie Don , Garner Ted , Yurkanin Josh 
Published: December 2007

Abstract
The waterflood is the most widely used and most successful secondary recovery technique in the oil industry. The injection of produced or make-up water into an oil reservoir can increase recoveries from an average of 19% of original oil in place to as much as 55%1 by driving or sweeping additional oil from the reservoir as the water cycles from injection wells to production wells.
The challenge to operators of water flood fields is to maximize their water injection rates at as low a cost as possible since injection wells themselves are not revenue-generating assets. Just as production wells periodically require stimulation to improve productivity, the injection well also develops near-wellbore skin damage that reduces injectivity over time. Injection water quality and incompatibilities with native reservoir fluids can lead to scale or other debris blocking pore throats and reducing near-wellbore permeability – thus requiring stimulation.
A large percentage of California injection wells are completed across multiple sands. Although fracture stimulation treatments generally result in greater conductivity between the wellbore and the reservoir, acid stimulation remains the technique of choice for restoring the injectivity of the majority of these wells. A fracture treatment would result in communication of these sands behind casing and eliminate the ability of the operator to control which sands are taking injection water.
This paper discusses unique acidizing chemistry and placement techniques that have demonstrably improved injectivity while maintaining the integrity of the barriers between sands in a number of waterflood fields in California. Optimization of acid chemistry and placement improves the depth of penetration of the treatment, reduces the risk of near-wellbore formation deconsolidation, extends treatment life, and reduces the overall cost per barrel of water injected.
Ultra Lightweight Proppants: Their Use and Application in the Barnett Shale
Authors: Schein Gary W. , Carr Philip Dale , Canan Patrick A. , Richey Ray 
Published: December 2007

Abstract
One of the more active areas for drilling gas wells has been in the Fort Worth Basin in North Texas in a fractured shale formation called the Barnett Shale. Over 2000 wells have been drilled in this non-conventional gas reservoir over the past five years. Initial stimulation treatments in the Barnett Shale began in the early 1980&#39;s and consisted of pumping moderate fracture stimulations of approximately 300,000 gals. of fluid and 300,000 lbs. of proppant, typically sand. These treatments quickly evolved to massive hydraulic fracture treatments that used extremely large volumes of conventional crosslinked fracture fluids utilizing over 750,000 gallons of fluid and over 1.0 million pounds of sand. These treatments continued to evolve through early 1997 based on the success in the East Texas area of the slickwater fracturing technique being applied to tight gas sands, in particular the Cotton Valley Sand. Since that time many operators have found success in these types of reservoirs utilizing large volumes of slickwater with low concentrations of proppant. A major concern in utilizing slickwater and fracture injection rate as the only means to transport proppant into the reservoir is the inefficiency of obtaining the most effective propped fracture.
The next evolution to improving proppant transport and ultimately more effective fracture length is the use of Ultra Lightweight proppants. This paper will present the application and results of fracture treatments performed in the Barnett Shale using a new ultra lightweight propping agent. The paper will also discuss the applicable Newtonian solids transport theory and it&#39;s relation to the density of the proppant and the fluid in which it is being pumped.
Reduced Polymer Based Fracturing Fluid: Is Less Really More?
Authors: Dawson Jeffrey C. , Cramer David D. , Le Hoang V. 
Published: December 2007

Abstract
A new generation of guar gum is produced in a manner that provides high crosslinked fluid viscosity. The ultra high efficiency of these polymers enables polymer concentration (loading) to be reduced without sacrificing essential fracturing fluid properties such as rheological performance, proppant transport and fluid loss control. Reduced polymer loading also provides enhanced clean-up allowing for better utilization of fracture length, as measured by lower flow initiation stresses, and higher proppant pack conductivity. These factors positively influence well productivity. These polymers are also more tolerant to both KCl and a wider range of mix waters.
Field loadings of the new polymer typically range from 15 to 30 lb/1000 gal of water (i.e., 15 to 30 pptg), with most treatments ranging from 15 to 20 pptg. This paper will describe the results of rheological measurements made on low polymer crosslinked gels using steady shear. Proppant pack conductivity and regained permeability testing will also be presented. In particular, numerous treatments have been pumped into wells completed in the tight sands of the Unita, Piceance, Greater Green River and Wind River Basins of the Rocky Mountain province. Comparative post treatment analysis, utilizing basic indication techniques such as normalized production (e.g., gas production/ net pay) at fixed reference times (e.g., 30-day cumulative gas) will be presented. In addition, a more comprehensive analysis using well testing (drawdown) methods will also be included as a means to evaluate the benefits of using borate crosslinked fluids based on lower polymer loadings.
Interactive Log Simulation and Inversion on the Web
Authors: Polyakov V. , Habashy T. , Kocian R. , Pabon J. , Anderson B. 
Published: December 2007

Abstract
Log simulation is critical for understanding and interpreting logging tool responses. It helps the log analyst understand near-wellbore measurements in complex environments, and particularly in anomalous situations. Simulated logs can also be used in "what-if" scenarios or as part of an iterative scheme to invert for the formation&#39;s geometry and material properties. We describe our implementation of a forward modeling and inversion environment with a multitier, Web-based architecture. The Web platform offers universal access from the user&#39;s desktop through a common Web browser to the simulator engine, running on a high-performance compute server. The application also allows the user to invert for near-wellbore rock properties from a set of logs. In addition to user-accessible Web pages for interactive use of the application, a programmatically accessible log simulation Web Service is created. Regardless of the host platform, this allows any networked application to access the simulator library without the need to replicate code, thus facilitating the development of formation evaluation applications. Because the library is hosted on a high-performance cluster (HPC), the computational engine always runs in the shortest possible time.
Web Based Evaluation, Design and Updating of a Reservoir Control System
Authors: Polyakov V. , Ramakrishnan T. S. 
Published: December 2007

Abstract
Optimal hydrocarbon production is facilitated by a continual adjustment of wellbore pressure or flow rate, most easily implemented with an automated control system. For each well, this system consists of a tuned logic controller, a remotely operable throttle valve, and sensors such as pressure transducers and/or flow meters. Joint modeling of the reservoir and the control components is necessary for tuning the feedback algorithm in order to have a stable and acceptable rate of response (SPE 84219). Given the target audience, a platform independent user-friendly front-end is desirable; but the system evaluation is computationally intensive, thus necessitating a sophisticated back-end server. To this end, we present a multi-tier Web application that offers a universal interface to a simulator running on a central compute server. The rendering of the Web interface is driven by the data. The application delivers the simulation input data to the compute server through a relational database. The results may be examined online and parameters adjusted until a satisfactory step response is obtained. The method is also applicable for downloading tuned parameters to a semi-autonomous wellsite controller.
Geologic Sequestration of CO2 in a Depleted Oil Reservoir: An Overview of a Field Demonstration Project
Authors: Pawar Rajesh J. , Warpinski Norm R. , Benson Robert D. , Grigg Reid B. , Krumhansl James L. , Stubbs Bruce A. 
Published: December 2007

Abstract
Sequestration of Carbon dioxide (CO2) in deep, geologic formations is one of the options currently being studied to mitigate the amount of CO2 released to the atmosphere. Depleted oil and gas reservoirs are one of the geologic targets considered for sequestration. Even though CO2 is currently being used in the enhanced oil recovery operations, injection of CO2 in depleted oil reservoirs as a carbon sequestration strategy needs validation. This paper provides an overview of the first U.S. field test of CO2 sequestration in a depleted oil reservoir, sponsored by the United States Department of Energy. The main objective of the project is characterization of CO2 migration through an integrated study that includes, field/laboratory experiments and numerical simulations. A small-scale field experiment was conducted whereby approximately 2100 tons of CO2 was injected in the West Pearl Queen Field, NM over a two-month period. Migration of CO2 was monitored using high-resolution 4-dimensional surface seismic surveys as well as downhole pressure monitors. Comparison of pre-injection and post-injection surveys indicates presence of an anomaly within the vicinity of the injection well, which could be resulting from injected CO2. After a 6-month soaking period CO2 was vented from the injection well. The amount of reservoir fluids produced during venting was monitored. A number of samples of reservoir fluid and gas were collected for compositional analyses. Changes in chemical compositions of fluid samples were observed indicating interaction between CO2 and reservoir fluids. The field experiment data are currently being integrated along with laboratory experiment data and numerical simulations to determine reservoir response to CO2 injection and to perform long-term fate calculations for such CO2 sequestration operations.
Underbalanced Drilling: Improving Pipe Connection Procedures Using Automatic Control
Authors: Nygaard Gerhard H. , Vefring Erlend H. , Mylvaganam Saba , Lorenzen Rolf Johan , Nævdal Geir , Fjelde Kjell Kåre 
Published: December 2007

Abstract
Controlling the well pressure in the reservoir section during underbalanced drilling is of paramount importance for successful underbalanced drilling operations. Transient events caused by pipe connection lead to challenges in controlling the well pressure. Simple, manual procedures are used today to keep the well pressure in the reservoir section below the reservoir pore pressure.
In this paper we investigate the possibility of using an automatic control methodology to maintain the well pressure in the reservoir within critical limits, using a transient well/reservoir model. This model is used to predict the future pressure conditions based on the present status of the well. The results from a model-based control method are investigated and compared with those of conventional control methods.
The transient model combines a dynamic well model based on a drift-flux formulation, and a near-well transient reservoir model. Our focus is to maintain an underbalanced condition along the reservoir zone using the combined model, by controlling the choke setting and the pre-connection fluid flow rates in the well.
The nonlinear model predictive control method estimates the states and parameters along the well and within the reservoir, based on the available measurements and the information from the combined model. Based on these estimates of the well and reservoir parameters, the future behaviour is predicted using the combined model. The optimal choke settings and fluid flow rates prior to pipe connection are found.
The methodology has been applied to two different field based cases. The results indicate that the methodology is very promising as a tool to control the well pressure while performing pipe connections during underbalanced drilling.
New Flat-Rheology Synthetic-Based Mud for Improved Deepwater Drilling
Authors: van Oort E. , Lee J. , Friedheim J. , Toups B. 
Published: December 2007

Abstract
In deepwater drilling operations, synthetic based mud (SBM) is the preferred drilling fluid because it delivers high drilling rates and excellent wellbore stability. However, lost circulation problems caused by adverse elevation of viscosity and increase in equivalent circulation density (ECD) as a function of temperature and pressure often result in significant operational cost increase. Controlling the pressure and temperature dependence of SBM rheology thus is an important step towards achieving successful and cost-effective deepwater drilling operations.
This paper highlights the development and application of an improved SBM that optimally balances the requirements for excellent rheological properties, ECD control, and improved barite suspension. Unlike conventional SBMs, the new SBM exhibits a constant ("flat") rheological profile over a wide temperature and pressure range. For instance, certain key rheological parameters, such as 6-rpm reading, yield point, and gel strengths, remain virtually unchanged when temperature and pressure are varied. This flat-rheology characteristic allows for a higher viscosity to be maintained without negatively affecting drilling rate or ECD. Moreover, cuttings carrying capacity and barite suspension properties are greatly improved.
The flat-rheology profile is achieved through the usage of a re-designed package of emulsifiers, rheology modifiers and viscosifiers. The emulsifier package minimizes the impact of drill solids on the rheological properties of the new SBM. Optimal rheology modification is achieved through minimal use of organophilic clays. Moreover, a new rheology modifier also reduces the key viscosity parameters at low temperatures while raising them at high temperatures. The viscosifier is used to provide the desired enhancement in overall viscosity and suspension capacity.
Extensive field data from Gulf of Mexico (GoM) wells (including drilling performance data, ECD and downhole pressure data, etc.) shows the benefits of the new flat-rheology SBM (FR-SBM) system, including lowering of ECD (resulting e.g. in lower SBM mud losses), improved cuttings evacuation from the well and prevention of barite sag problems. The operational success of FR-SBM has led to rapid acceptance in the field, allowing it to displace conventional SBM in Shell's GoM deepwater drilling operations.