bluuebunny/crossref_metadata_2025 huggingface dataset:
Using Cost Effective Tools to "Bring the Wells to the Operators!"
Authors: Cramer Ron , Der Kinderen Wim , Berendschot Leo
Published: December 2007

This paper describes a cost-effective, pragmatic way to continuously monitor and control well performance for most oil well types. Well fluid flow rate estimates are displayed in graphical form as trends on user desk top PCs. Deviations from the norm are flagged as process alarms. In some cases measured fluid flow changes are used to automatically control the well by adjusting choke settings for performance improvement.

The main benefits of this approach are safer operations and reduced operating costs - operators visit only wells with problems thus reducing exposure to hazard and eliminating spurious travel and logistics. Other benefits include increased production due to early warning of well problems, better understanding of well behavior, improved allocation accuracy and improved well testing.

The purpose of this paper is to describe Shell experience with low cost continuous well performance devices and some of the benefits that can be gained from this approach.
Business Ethics, Corporate Social Responsibility, and Firm Value in the Oil and Gas Industry
Authors: Fadul Javier , Maurer Ruth A.
Published: December 2007

This study is an examination of the relationship between ethical behavior, corporate social responsibility, and firm value in companies in the oil and gas industry. The considerable social impact of the behaviors and actions of oil and gas companies and their undeniable weight in the overall economy drive the purpose of this research. Ethical behavior and social responsibility of the sampled oil and gas companies will be conceptualized by a series of ethical and social indexes used to carry out empirical observations representing those concepts. Each social index will be analyzed using statistical data analysis techniques to establish if there is any significant relationship with the firm's value. This research presents empirical evidence examining whether, along with other standard factors, corporate social responsibility is associated with the firm value of companies in the oil and gas industry.
Cased-Hole KUTh Logging Using A PNS Tool
Authors: Reed Skip , Jacobson Larry A. , Durbin Dennis
Published: December 2007

Traditionally, all major service companies have had an openhole spectral gamma tool in their arsenal that will measure the naturally occurring potassium (K), uranium (U), and thorium (Th) radioactivity surrounding a borehole. KUTh data are used in various ways, such as subtracting out high API uranium indications from total API Gamma Ray readings in radioactive formations and using the relative percentages of these elements as input to proprietary mineral calculation programs.

Recently, a standard C/O logging tool with the neutron generator turned-off was used for cased-hole KUTh logging with good results. Although this pulsed neutron spectrometry (PNS) tool was a slim tool (2 1/8-in. diameter), the log quality was comparable to that achieved by earlier, large diameter gamma spectrometry tools because this particular PNS tool utilized a high density scintillator. This experience clearly demonstrated that reliable spectral gamma measurements can be made in cased hole. Calibration with a standard thorium calibration sleeve allows the operator to set the spectral gain of the system (using the Th peak); and this value of gain is used during the logging operation. After logging, the data is reprocessed with software that tracks and corrects any gain drift due to temperature producing the final corrected log. Concentrations of K, U, and Th are extracted using a weighted-least-squares (WLS) fit of standard elemental (basis) spectra to the log data during the re-log phase.

Measurements made in this way can readily precede the standard formation evaluation run in a well and use essentially the same instrumentation and thus replace traditional openhole KUTh measurements. The enhanced design and the software associated with it provide high quality formation evaluation information; and this information can be made available with no associated drilling rig cost if the tool is run going in the hole.

This paper will show field examples of KUTh data. The paper will also discuss procedures necessary to obtain quality measurements, will point out various savings that can be realized by an operating oil company using the new design and the information it gathers, and will present the interpretation procedures necessary to obtain a final product.
Important Modeling Parameters for Predicting Steamflood Performance
Authors: Satik Cengiz , Kumar Mridul , DeFrancisco Sam , Hoang Viet , Basham Mike
Published: December 2007

A comprehensive numerical study was performed to investigate impact of pattern confinement on simulation results, using a three-phase and three-dimensional thermal reservoir simulator. In addition, effects of cyclic steaming the producers, grid size, and other physical parameters were evaluated. Detailed multi-pattern, single-sand steamflood models were constructed using properties of a heavy oil field in California. All models included an initial primary depletion zone of 6 ft within 60 ft of net pay. Up to 25, 2.5-acre patterns were included in the study.

Results show that finely gridded models capture near vertical steam override, and oil drainage by gravity with a near horizontal steam/oil interface accurately. High injection pressures observed in many prior simulations are primarily a result of confined reservoir models. Steam zone pressures and temperatures are similar to those typically observed in the field, when the model is unconfined (model area is greater than pattern area), representing undeveloped portions of the field. Moreover, including cyclic steaming of producers accelerates the steam breakthrough time (BT) and lowers injection pressures. During post-breakthrough steam rate reduction period, field-observed oil production response is better represented when the influence of surrounding patterns is included. Production rate decline is small when injection rate is reduced only in the primary pattern(s); however, the decline rate increases if rate reduction is implemented in the entire modeled project area.
A New Computational Fluid Dynamics Model to Predict Flow Profiles and Erosion Rates in Downhole Completion Equipment
Authors: Russell Ronnie , Shirazi Siamack , Macrae Jonathan
Published: December 2007

Flow velocities and sand generation encountered in high-volume oil wells have exceeded the accuracy of current CFD modeling data. Advanced theoretical work and erosion modeling have been performed to address these high flow rates. The theory and models are compared and verified by testing several materials under an array of flow conditions. The models and test data provide a valuble design tool to ensure performance and reliability of critical completion hardware.

Introduction

Sand production is a major problem in oil and gas production operations. The presence of sand in produced fluid presents many challenges to equipment suppliers and production companies. Sand control has become increasingly important as high-rate wells with sand become more prominent. Sand erosion as a result of sand production is a major concern. It causes loss of pipe wall thickness that can lead to expensive failures and lost - production. Even when sand production is as low as a few pounds per day, it can cause erosive failure at high production velocities. Laboratory experience indicates that when the produced fluid is a liquid, exchange of momentum between sand particles and liquid reduces the impact velocity of sand particles, resulting in little or no erosion. However, current erosion data does not cover the range of materials and flow conditions experienced in high flow rate oil wells.

American Petroleum Institute Recommended Practice 14E (API RP 14E) provides a criterion for sizing gas/liquid two-phase lines on the basis of flow velocity. The recommended practice states that (API RP 14E, 1991):

"The following procedure for establishing an ‘erosional velocity’ can be used where no specific information as to the erosive/corrosive properties of the fluid is available. The velocity above which erosion may occur can be determined by the following empirical equation:Equation 1

where:

Ve=fluid erosional velocity, ft/sec

c=empirical constant

?m=gas/liquid mixture density at flowing pressure and temperature, lb/ft3

Industry experience to date indicates that for solids-free fluids, values of c=100 for continuous service and c=125 for intermittent service are conservative." The recommended practice adds: "If solids production is anticipated, fluid velocities should be significantly reduced. Different values of ‘c’ may be used where specific application studies have shown them to be appropriate."

Eq. (1) is simple and easy to use, but it does not account for many factors contributing to erosion/corrosion. The only physical variable accounted for in Eq. (1) is the fluid density. The equation suggests that the limiting velocity could be higher when the fluid density is lower. This does not agree with experimental observations for sand erosion, because sand in gases with lower densities will cause higher erosion rates than liquids with higher densities. Therefore, the form of Eq. (1) does not seem to be appropriate for situations involving sand production.
Stimulating Sandstone Formations with non-HF Treatment Systems
Authors: Martin A. N.
Published: December 2007

Recent advances in acidising technology mean that it is now feasible to effectively and efficiently stimulate sandstone formations, using acid systems not containing hydrogen fluoride (HF). Although quartz and certain silicate materials are not significantly dissolved by non-HF systems, there are a significant number of minerals and deposits that can be completely or partially removed. This means that formations that have been considered difficult to stimulate with HF-containing systems, may in fact be the best candidates for non-HF systems.

Over the last decade, tremendous advances have been made in the application of HF-based systems in sandstone formations. The technology has moved from "hit or miss" conventional HCl:HF systems, to significantly more chemically specific systems. Such systems can be used with an extremely high success rate, when applied scientifically and systematically. Nevertheless, there are still many sandstone formations that cannot be successfully stimulated using even the most advanced HF systems, such as those with a high content of carbonate minerals or highly reaction-sensitive clays. However, non-HF systems are now available that can stimulate such formations successfully and cost-effectively - without causing damaging precipitation of acid reaction by-products or near-wellbore formation deconsolidation.

This paper outlines the mechanisms of sandstone formation mineral dissolution by various non-HF acid systems, and more importantly, the prevention of post-treatment damage, including secondary, tertiary and quaternary precipitation reactions. It will also detail methods by which long-term improvement in productivity can be achieved in formations that are prone to suffer from scale formation or water production. Case histories will be used to illustrate application of these unique treatment methods.
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

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

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

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

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

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

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'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'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

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

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'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'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

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

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

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

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.
Improved First-Motion Algorithm to Compute High-Resolution Sonic Log
Authors: Valero Henri-Pierre , Tejada Mauricio , Murray Doug
Published: December 2007

Estimation of formation slowness is of significant value for petrophysical and geomechanical applications. To do this, a source excites a signal in the borehole, which couples with, and propagates within, the formation prior to being recorded by receivers. Generally, sonic tools are composed of one or more transmitters and an array of receivers. A next generation sonic tool developed by Schlumberger is composed of 3 monopole and 2 dipole transmitters. The receiver array is composed of 13 receivers separated by 6 inches. Waveforms are digitized at the sensor with a dynamic range of 16 bits. Digitizing the waveform at the sensor will guarantee optimal data quality as the waveforms will not be corrupted by electronic noise or other undesirable effects. The general technique used to measure formation slowness is based on semblance processing which was first proposed 20 years ago. Semblance processing is robust and provides reliable results in most cases but its vertical resolution is linked to the length of the tool array. Practically, it means it is not possible to detect beds that are smaller than a tool's array length. Hence, it can be difficult to compare slowness logs with other datasets of much higher vertical resolutions.

In order to alleviate this problem, we propose an improved first motion algorithm to compute a high-resolution sonic log. The technique considers that the part of the waveform before and after the first break can be modeled as an AR process. The key parameters of this approach are the "model order", which describes the data and the part of the waveform to be modeled. In this paper we will show that the use of the Bayesian Information Criterion combined with the computation of the envelope of the signal will allow for an automatic computation that is suitable for wellsite operations. We will demonstrate that this first motion technique does not require any human intervention and in most cases provides a robust and reliable result. This algorithm will then be applied on real data and the high-resolution log obtained will be compared with other high vertical resolution measurements.

Introduction

Evaluation of formation slowness using sonic tools is important in oil exploration. This physical measurement allows geophysicists to calibrate their velocity models, and petrophysicists to obtain a porosity estimate of the reservoir. Measurement of the compressional and shear acoustic slownesses of the formation is usually made in open hole. The conventional method is to acquire monopole data, which is used to determine the compressional slowness. If the shear slowness is required, and if it is faster than the mud slowness, it can be obtained from monopole data with waveform processing. In slow formations dipole mode data may also be acquired to provide shear information and can provide redundancy for the monopole shear measurement in fast formations. These results are generally well established and reliable in most cases.
Maximizing Productivity in the Scoter Gas Condensate Field, UKCS: A Multidisciplinary Approach to Expandable Sand Screen Design and Subsea Installation
Authors: Al-Lamki Ali , Twycross Jean , Clarke Gillian
Published: December 2007

Expandable Sand Screens (ESS®) were deployed successfully in two gas-condensate subsea production wells on the Scoter field, in the UK sector of the North Sea in May 2003. The Shell UK operated 22/30a-S1 (Scoter P1) and 22/30a-S2 (Scoter P2) wells are near-vertical, drilled from the semi-submersible rig, Ocean Guardian, and penetrate the Forties sandstone. Well clean-up performance to the rig (June 2003) and first production to the Shearwater processing platform (December 2003) exceeded original expectations.

The success of the Scoter 4" ESS installation has been due, in part, to the multi-disciplinary approach taken by both Shell and Weatherford, from concept selection to after-action review. This paper details learnings on the extensive ESS design and execution including: Torque and drag analysis for screen running in and expansion to minimize damage.Determination of rig-heave effects on screen expansion from an Axial Compliant Expansion (ACE) tool.Use of long-term, synthetic core baking-tests (at temperature) to estimate the effect of completion-to-clean-up time on reservoir return permeability: initial production data showed no evidence of skin (no wellbore damage or screen plugging for both wells).Erosion and collapse modeling of the screens.Well clean-up and bean-up, including offshore petroleum engineering support.Sand control contingency planning (e.g. external gravel pack sand control design, including mud selection testing).Simplified completion including use of a Formation Isolation Valve (FIV)

This technical knowledge can be adopted elsewhere for future sand control applications, including: Any design and installation of ESS, especially from a semi-submersible rig.Any return permeability testing, especially to assess the effect of delayed clean-up on reservoir return permeability.Any clean-up of a gas-condensate ESS well.
Attic Oil
Authors: van der Poel C. , Killian J.W.
Published: December 2007

The area that can be swept by a natural water drive in a dipping reservoir above the structurally highest wells is investigated mathematically and with a parallel plate flow model. This swept attic area (above the structurally highest wells) is found to be a function of two parameters. The first parameter describes the relative influence of the viscous potential gradient or "drawdown" at the well tending to move such oil down from this attic space, and the buoyant force of gravity tending to keep the oil in the attic. The ultimate area that can he swept if production is continued to 100 per cent water-cut is a function of this parameter alone. The second parameter is a combination of water-cut and mobility ratio, and is a measure of the fraction of this ultimate swept area that is actually swept. The attic area swept can vary from zero or even slightly negative amounts, up to perhaps half the square of the well spacing for very favorable circumstances. (There is no theoretical limit on the ultimate area swept as the production rate, for example, is increased. But extremely large ultimate swept areas are approached so slowly that they are not closely realized at even quite high water-cuts.) At sufficiently unfavorable mobility ratio and high production rate, fingering will occur. Fingering reduces the swept area at low water-cuts, but has little effect at high water-cuts. Charts given in the report enable rapid calculation of swept areas for specific field cases, and a criterion is given for fingering.

The complete flow pattern is determined theoretically for the 100 per cent water-cut case. The computed interface shapes and areas swept are in good agreement with the model results. The production history for unit mobility ratio and negligible buoyancy also is determined theoretically, which serves as a guide in correlation, and agrees well with the experimental (model) data.

Introduction

The determination of the amount of oil recoverable updip of the structurally highest wells in a strong water-drive dipping reservoir is particularly important for salt-dome fields, such as at Weeks Island, where it often is not feasible or desirable to complete wells right up against the salt dome.
A Probabilistic Analysis of the Economics of Oil Recovery From the Athabasca Tar Sands
Authors: Iskander Fadel F. , Ikoku Chi U.
Published: December 2007

A general-purpose probabilistic economic evaluation model for petroleum investment ventures has been developed. The model’s operation is demonstrated by considering an actual field in Alberta, where an economic evaluation of the feasibility of producing the Athabasca tar sands is conducted. An oil recovery method (COFCAW) is applied, and necessary input data are selected. Other oil recovery methods may be evaluated by modifying the input data.

The model allows the use of five continuous input probability distributions as well as a discrete input distribution. Input for the continuous distributions is entered as a three point estimate (low, medium, and high), whereas input for the discrete distribution is entered as a number of values and their respective cumulative probabilities of occurrence. The maximum number of values allowed is nine.

The model calculates possible production rates which are directly dependent on the calculated recoverable reserves. The production rates are used to calculate total revenue; this is followed by calculating direct and indirect cost items, taxable income, taxes, earnings after tax, non tax deductible items, cash outflows, and net cash flows. These net cash flows are used to calculate three profitability measures: the discounted cash flow rate of return, a modified rate of return, and the net present value.

The results obtained are summarized as follows: the discounted cash flow rate of return, the modified rate of return, and net present value calculated had average values of 35%, 30%, and $10.5 million, respectively.

A sensitivity study on the input variables was conducted to identify the critical variables whose input values have an impact on the results of the model. Among the most critical variables are well operating expenses, inflation rate on the operating expenses, bitumen selling price, and inflation rate on that price. It is also observed that the modified rate of return is the least sensitive to input data variations of all profitability measures considered.
Oil, Gas and Geothermal Energy Picture in Japan
Authors: Hirakawa Seiichi
Published: December 2007

This paper will try to explain mainly about oil, natural gas, liquefied gas and geothermal energy in Japan. Consideration is concentrated on the role of these energy through showing the relation with these energy and Japanese energy policy. The problems concerning Japanese industrial and technological aspects of these energy are also broached.
Seismic-While-Drilling Using a Swept Impulse Source
Authors: Kolle J. J. , Theimer K.
Published: December 2007

This paper describes a prototype swept impulse hydraulic tool capable of generating a broadband seismic signal at the bit while drilling. The source was designed to overcome the limitations of drill bit seismic services by allowing operations with PDC bits in inclined wells and in soft formations. Operating principles, seismic processing techniques and results of a field demonstration of seismic profiling while drilling in a shallow well are described. Downhole tests of a prototype swept impulse tool were conducted in a deviated well while drilling with a PDC bit at depths of 2000 to 2500 feet. These tests represent the first demonstration of reverse vertical seismic profiling while drilling with a PDC bit or while drilling in an inclined well. The swept impulse seismic source generated a broadband, high-intensity compression wave signal that can be used for high resolution seismic profiling and look-ahead imaging while drilling. Velocity measurement accuracy is comparable to checkshot/VSP or sonic log and the information is available in real time with no interruption of conventional drilling operations.
Measurement and Analysis of Induced Torsion in Helically Buckled Tubing
Authors: Zdvizhkov A. , Miska S. , Mitchell R.
Published: December 2007

In the original publication on helical buckling by Lubinski, Althouse and Logan (1962) it was assumed that no torsion can be developed in buckled tubular string (Lubinski-Woods problem) if there is no casing-to-tubing friction and tubing remains in elastic range of bending.

The recent theoretical work by Mitchell1 (2003) presented the large displacement analysis of helically buckled slender beam and predicted, that shear force and twisting moment are induced in helically buckled pipe without externally applied torque.

In short, there is an induced left-hand torsion in tubing buckled into right-hand helix that is surprisingly large and in some cases may approach or exceed the make-up torque values for connections.

For study of this phenomenon an experimental facility was setup at The University of Tulsa, depicting straight horizontal wellbore with the inner steel tubing 0.50" (12.7mm) OD and outer acrylic tube 1.90" (48.3mm) ID representing drillstring and wellbore respectively.

For precise measurement of pure torsion in the tubing, the strain gages, arranged into the full torsion bridge configuration were employed.

The experiments were performed with "bottom end" of the steel tubing held stationary and axial buckling force applied from the "top end".

The end conditions for the tubing were represented by clamped and pinned connections.

It was observed that torsional equilibrium in the tubing is disturbed as soon as buckling force is applied with further increase in torsion as shape of the tubing is transforming from sinusoidal into helical.

Upon the tubing reaching full helical shape, the internal torsion continues to increase with increase of axial buckling force in the manner predicted theoretically.

The results of this study are important for practical design and analysis of drillstrings and completion tubing.