bluuebunny/crossref_metadata_2025 huggingface dataset:
Low-Salinity Waterflooding to Improve Oil Recovery—Historical Field Evidence
Authors: Robertson Eric P
Published: December 2007

Waterflooding is by far the most widely applied method of improved oil recovery. Crude oil/water/rock interactions can lead to large variations in the displacement efficiency of waterfloods. Laboratory waterflood tests and single-well tracer tests in the field have shown that injection of low-salinity water can increase oil recovery, but work designed to test the method on a multi-well field scale has not yet been under-taken. Historical waterflood records could unintentionally provide some evidence of improved recovery from water-flooding with lower salinity water. Numerous fields in the Powder River basin of Wyoming have been waterflooded using low salinity water (about 1000 ppm) obtained from the Madison limestone or Fox Hills sandstone. Three Minnelusa formation fields in the basin were identified as candidates for waterflood comparisons based on the salinity of the formation and injection water and reservoir characteristics. Historical production and injection data for these fields were obtained from public records. Field waterflood data were manipulated to display oil recovery in the same format as laboratory core-flood results. Recovery from fields using lower salinity injection water was greater than that using higher salinity injection water—matching recovery trends for laboratory and single-well tests.
A New Environmentally Acceptable Technique for Determination of Propped Fracture Height and Width
Authors: McDaniel R. R. , Borges J. F. , Dakshindas S. S.
Published: December 2007

For years, radioactive tracers have been used in combination with standard industry logging tools to gain valuable insight about the fracture height (near-wellbore vertical coverage) of proppant-packed fractures. The existing tracer technology has a number of safety and environmental issues that must be addressed when using this technology as part of a fracturing treatment. These issues, along with regulations concerning the transportation of radioactive materials, have impacted the application of this technology in international markets.

This paper will describe a new patent-pending technology that can generate valuable data on propped fracture height, as well as insight into propped fracture width. In this new technology, a non-radioactive tagging additive is incorporated into the resin coating of the proppant. This non-hazardous, environmentally safe, coated proppant can be transported and applied without any of the restrictions associated with radioactive tracers. Once the proppant is placed in the well, a gamma spectroscopy logging tool is used together with a fast neutron source to activate the tagging additive. The additive then becomes temporarily radioactive, emitting characteristic gamma rays that are visible to the logging tool's spectrometer.

The detected gamma ray response not only identifies the presence of the proppant, but in addition, the strength of the response is proportional to the amount of the additive/proppant that is present in the fracture, thereby providing insight on fracture width. Since the additive only responds when stimulated by the neutron source, the logging process can be completed free of any of the timing constraints associated with the half-life of presently used radioactive tracers and can be repeated as often as desired.

The additive used in this technology has been selected for a number of reasons, not the least of which is its very short half-life after being irradiated. By the time the logging process is complete and the well is ready to be placed in production, the additive will no longer emit a detectable level of radiation. This paper will describe this technology and its use in some detail. It will also present the results of initial field tests that utilized this new technology to determine aspects of propped fracture geometry.
The Challenges of Designing HP/HT Equipment
Authors: Forsyth Andrew , Saucier Brian , More Daniel , Stawaisz Ray A. , Gill Dave , Younger Ray
Published: December 2007

The Paper presents an overview of the main design activities for the Completion and Intervention Landing String System that was deployed in the Tahiti field in the Gulf of Mexico. The functional and structural design challenges encountered due to the high operating pressures and temperatures are reviewed. The Paper also illustrates how analysis tools were used to quantify the observations found during test, and subsequently assist in determining a design solution. A key aspect of the design process was to view the design and operations from a holistic perspective by evaluating the design throughout its operational life. This paper will therefore present how this design process established a design solution that increased the reliability and confidence of the Landing String System and therefore reduced the operational risk.
Application of the CPA Equation of State to Reservoir Fluids in Presence of Water and Polar Chemicals
Authors: Yan Wei , Kontogeorgis Georgios M. , Stenby Erling H.
Published: December 2007

The complex phase equilibrium between reservoir fluids and associating compounds like water, methanol and glycols has become more and more important as the increasing global energy demand pushes the oil industry to target reservoirs with extreme or complicated conditions, such as deep or offshore reservoirs. Conventional equations of state (EoS) with classical mixing rules can not satisfactorily predict or even correlate the phase equilibrium of those systems. A promising model for such systems is the Cubic-Plus-Association (CPA) EoS which has been successfully applied to well-defined systems containing associating compounds. In this work, CPA is extended to reservoir fluids in presence of water and polar chemicals by using a newly developed characterization procedure for ill-defined C7+ fractions. Satisfactory results are obtained for multicomponent systems using a minimum number of adjustable parameters which are obtained from binary systems. Modeling of mutual solubility between light hydrocarbons and water is also addressed.
Gannet A: Critical New Reservoir Insight Through Seamless Cross-Discipline Integration
Authors: de Jonge Joanne , van Waarde Jakko
Published: December 2007

The thin oil rim of the Gannet-A turbidite field in the Central North Sea has been produced since 1993 though 11 long horizontal wells supported by a strong aquifer and sizeable gas cap. The original zero development strategy called for zero net-voidage of gas through re-injection of produced gas into the gas cap.

A full gas cap blowdown is currently being planned to commence in 2008. In order to predict field behaviour in this high production rate environment, and maximise oil and gas recovery, significant effort has gone into the static and dynamic re-modelling of the reservoir.

This effort has demonstrated that over the production life, complexity of the high quality reservoir has been underestimated, leading to inadequate historical data acquisition and integration efforts, particularly in the low oil price world in the late 90s.

This paper describes how all available subsurface data have been (re-)analysed and integrated, resulting in a range of realistic dynamic reservoir models and how the remaining uncertainty was dealt with during the selection of the optimum further field development plan.

The key to success in this study has been the seamless cross discipline integration that enabled maximum extraction of information from the available data. The same discipline integration led to a thorough understanding of the critical remaining uncertainties in the project and a tailor made surveillance plan that aims at rapidly reducing these.
Certification Process Built on Required Engineering Competency Standards Ensures Consistent Performance Levels and Defines Employee Development
Authors: Scotchman A. D. , Redshaw J. P. , Laing R. , Forstner I. , Trichel D. K. , Dwyer J. P.
Published: December 2007

In today's robust hydrocarbon markets, complexity and volume of drilling and evaluation activity have grown to unprecedented levels. This is driving technology development and new application practices at a record pace. At the same time, the industry is struggling to grow the talent base to manage the increased workload. These issues have resulted in a need to track and ensure application engineer and geoscientist competency levels. To solve this challenge, the company developed a detailed process for individual competency assessment and employee development for various application disciplines. Certification is awarded in set disciplines when the necessary criteria have been met and competence has been successfully demonstrated to a technical experts’ review panel.

The required competencies for each discipline were developed from the expanded job functions expected of the experienced senior applications engineers and geoscientists, as well as expectations of the services provided in each discipline. From this, a competency assessment and tracking methodology was created. The methodology enables the assessment of an individual engineer's competency level so a tailored development program of training and mentoring can be developed. A formal mentoring system plays a vital role in the certification process. Assigned mentors offer valuable engineering and process guidance.

The authors will describe a certification process and a methodology for competency assessment and tracking for application engineers and geoscientists. Finally, the authors will discuss how the program benefits raise the level of the company's technical expertise.
Applying Hydraulic Fracture Diagnostics to Optimize Stimulations in the Woodford Shale
Authors: Vulgamore Travis , Clawson Tim , Pope Charles , Wolhart Steve , Mayerhofer Mike , Machovoe Sean , Waltman Charlie
Published: December 2007

The success of the Barnett Shale has many operators in search of similar producing formations. One such formation is the Woodford Shale which stretches from Kansas to west Texas. The Woodford is an ultra-low permeability reservoir that must be effectively fracture stimulated in order to obtain commercial production. Once a formation that was drilled through on the way to deeper horizons, this shale play now dominates drilling activity in southeast Oklahoma.

Like the Barnett, initial testing of the Woodford Shale was from existing vertical wells that penetrated deeper horizons. Currently, the main exploitation of the Woodford Shale is from long horizontal wells with some lateral lengths exceeding 4000 ft. The wells are stimulated in stages with large hydraulic fracture treatments. Successful shale plays have demonstrated that production is directly related to the size of the stimulated reservoir volume. Techniques to optimize hydraulic fracturing effectiveness have been evolving in the area the last few years.

Over 100 frac stages have been mapped in the Woodford Shale using surface tiltmeters, offset-well microseismic and treatment-well microseismic mapping techniques. This paper will examine the effect of lateral azimuth, formation dip and its influence on asymmetric fracture growth; the effect of existing faults and its interaction with the fracture stimulation. Additionally, stimulation size, number of stages, perforation clusters and fracture initiation problems will be discussed. Finally, a comparison to Barnett Shale type fracture networks will be made.

Understanding fracture growth in the Woodford Shale will enhance the development of the play by helping operators optimize fracture completion and well placement strategies.
Well-Stimulation Technology Progression in Horizontal Frontier Wells, Tip Top/Hogsback Field, Wyoming
Authors: Romer M. C. , Phi M. V. , Barber R. C. , Huynh D. V.
Published: December 2007

Fracturing work conducted on the 2006 Tip Top/Hogsback (TTHB) field horizontal well program proved that sand plug isolation will work in horizontal wells, even when the stimulation treatment calls for fracturing with a high energy fluid. The TTHB field is a tight gas field in southwestern Wyoming, and the wells will not produce without a fracture stimulation treatment. This paper will describe the evaluation process of various fracturing technologies considered for the program, and how learnings from a 1995 horizontal program were used to build the final pinpoint stimulation design. In addition, this paper will discuss the stimulation execution and the learnings generated from the program.

The fractured horizontal wells were drilled to 11,000 ft measured depth (MD), 7,200 ft true vertical depth (TVD), with the laterals being approximately 3,800 ft of the total measured depth. Eight fracture treatments were planned for each horizontal. The foam stimulation treatments contained 60-quality CO2 and averaged 235,000 lbm total proppant per zone. The basic stimulation procedure consisted of cutting perforation holes by use of a hydrajet tool on the end of coiled tubing (CT), pumping a fracture treatment down the production casing, and setting a sand plug with CT in the lateral to provide zonal isolation. This process allowed continuous treatment of successive intervals without shutting down to set a mechanical plug or perforate the next interval.

Although several challenges were encountered during the execution of the stimulation treatment, the stimulation design did prove to be a more time efficient and cost effective option than conventional horizontal well fracturing treatments. The paper will discuss learnings on setting sand plugs between fracs, frac designs, and equipment operation/limitations. As a result of the learnings, the average treatment time decreased from 24 hr/zone on the first well to 13 hr/zone on the second.

The paper will also discuss additional changes made during the stimulation execution to increase the effectiveness of the hydrajet tool and increase the probability of setting a successful sand plug.

The process for designing and placing successful sand plugs was optimized from well to well and can furthermore be tailored to fit other fields. Learnings and techniques applied in this work can be used to improve and optimize fracturing treatments of similar nature in other geographic/geologic areas.
Different Methods to Avoid Annular Pressure Buildup by Appropriate Engineered Sealant and Applying Best Practices (Cementing and Drilling)
Authors: Tahmourpour Farzad , Hashki Khaled , Hassan Hassan
Published: December 2007

Many wells that have been successfully cemented initially are showing annulus pressure buildup due to damaged cement sheath integrity by post-cementing operations/conditions. This has been a concern by many operators where wellbores may be exposed to severe conditions and/or production regimes over a period of time. Sometimes this problem can be temporarily dealt with by releasing the annulus pressure, if environmental conditions and well type will allow. However, this method of annular gas production relief is not a long-term solution to the problem. In addition, it is not always possible to reduce the annulus pressure by releasing the trapped pressure into the environment on a regular basis, even if all other conditions permit this operation. An engineered cement slurry system can save the operator from facing this situation by applying a lifetime zonal isolation remedy through the proper cement job design.

Gas injection in specific areas in the United Arab Emirates is performed to help maximize the production from these development fields. This paper will discuss the process of engineering a cementing system for these gas injection wells and the development of a solution that has successfully protected wellbores in gas injection areas where high pressures are applied to the wellbore. By treating the cement under defined wellbore conditions and studying the mechanical behavior of the cement sheath, it was possible to design a cement slurry system that could withstand the high pressures applied through gas injection operations. The mechanical behavior was evaluated using three-dimensional finite element analysis that considers mechanical properties such as Young's modulus, Poisson's ratio, and tensile strength in addition to confined compressive strength. The importance of complete zonal isolation is of high order. Elastic cement designs have provided a resilient nonfoamed, or conventional, system that successfully isolated the wellbores for more than a dozen gas injection wells.
Horizontal Wells in Tight Gas Sands—A Methodology for Risk Management to Maximize Success
Authors: Baihly Jason , Grant Dee , Fan Li , Bodwadkar Suhas
Published: December 2007

In general, successful applications of horizontal wells have been limited to high permeability reservoirs and unconventional formations such as coal, chalk, and shale. Conversely, few tight gas sandstone reservoirs that require stimulation have realized sustained success with horizontal completions. One example of such success is the Cleveland Sand of North Texas and Oklahoma Panhandle region. Very recently, some success with horizontals has been observed in the Bossier and Cotton Valley Sands of East Texas and North Louisiana. Horizontal wells are commonly two to four times more expensive to drill and complete than offset vertical wells, yet are theoretically capable of up to three to five times the production. Higher gas prices have lead to potentially better economics for horizontal wells. However, research shows that in practice, many of these wells typically produce only 10 to 30% more than offset vertical wells. With costs more than double those of vertical wells, the economics are obviously unfavorable.

This paper discusses ways to identify and manage risks when planning, drilling, and completing horizontal wells in tight sandstone formations in order to improve success.

Evidence has shown that shortcuts and blanket approaches usually do not work in these completion environments. A multitude of lithological and depletion possibilities exist as risks which need to be identified and managed through appropriate application of integrated drilling and completion technologies. Each risk may require different drilling and completion considerations to succeed. There is simply no magic recipe for repeat success.

A detailed methodology is presented to identify, understand, and manage risk associated with horizontal wells drilled in tight gas sandstone reservoirs. The methodology will address all of the complex subjects that need to be considered for the successful placement and completion of a horizontal well including reservoir description (both static and dynamic), well design, drilling, stimulation, and production. It will also illustrate consequences of what may happen if these issues are not properly considered. Through this methodology horizontal well feasibility and economic results can be determined. If a horizontal well has been determined to be economically viable, this methodology can consistently provide a solution as to what the best completion type (vertical or horizontal) is to recover reserves and enhance recovery efficiency in tight gas sandstone reservoirs.
Optimizing the Completion of a Multilayer Cotton Valley Sand Using Hydraulic-Fracture Monitoring and Integrated Engineering
Authors: Baihly Jason , Coolidge Andrew , Dutcher Steven , Villarreal Ruben , Craven Mike , Brook Keith , Le Calvez Joël H.
Published: December 2007

Microseismic hydraulic fracture monitoring is having a major impact in how wells are being completed in tight sand reservoirs. This existing technology is being utilized in new and innovative ways to provide operators a clearer picture of the fracture development. This information can be combined with other fracture diagnostic techniques, and along with sound engineering practices, can have a profound impact on how wells are completed.

This paper discusses the completion design methodology, execution, and results from two offset wells. The first well was completed with a two stage hydraulic fracture treatment while the successive offset was completed via a single-stage fracture treatment. The evaluation tools utilized to determine the resultant fracture attributes include microseismic hydraulic fracture monitoring, hydraulic fracture surface treating pressure-history matching, and tracer and production log interpretation in addition to production analysis. The results from each well are compared and contrasted, and a plan for potential future completions is discussed.

The microseismic event growth and fracture treating pressures over time revealed how the fracture propagated. In the first well the microseismic and treating pressure results of the first stage showed height growth into the proposed zone to be targeted by the second stage treatment. Lessons learned from the first subject well were then incorporated into the completion design of the offset well to optimize its overall completion efficiency. The second well was hydraulically fracture stimulated with a single stage treatment. The completion design changes incorporated in the second well showed some positive effects on the microseismic fracture geometry and resultant production.

An integrated analysis approach can provide an improved understanding of the fracture behavior within a field. This improved knowledge of the fracture system can lead to optimum completion designs and well spacing. These changes can then themselves be evaluated with the aforementioned tools to determine their level of success. This continuous improvement process can be repeated for future fieldwide well completion designs in order to achieve an optimum fracture system within the targeted intervals.
Characterization and Preservation of Karst Networks in the Carbonate Reservoir Modeling
Authors: Shen Feng , Qi Lixin , Han Gehua
Published: December 2007

Karstification was developed in the Ordovician carbonate reservoirs resulted from the action of meteoric waters during subaerial exposure. Poor core recovery and borehole imaging logs in permeable sections of the Ordovician carbonate reservoirs lead to poor understanding on karst networks. Due to the complex in geometry and lateral variability in thickness, features of karst networks cannot be clearly explained on 3D seismic. A new integrated approach is proposed, which consists of integrating 3D specially processed seismic geometric attributes, lithofacies and well log and drilling data into imaging karst networks and characterizing their effective properties. Geometric attributes, describing reservoir coherence, dip and lineaments, are seismic frequency dependent and allow reservoir architectures and karst features such as channels, dissolution fractures and sink holes to be identified in different frequency scales. The model-based classification technique is used to describe karst full geometry with estimated geometric attributes. The interpreted karst features are verified with total drilling losses encountered in drilled wells. To incorporate karst network geometries into a deterministic reservoir model, other reservoir heterogeneities based on their effects on reservoir connectivity and permeability are identified. The detailed reservoir architecture mapping for each layer related to karst connectivity and flow heterogeneity is the basis for the modeling carbonate reservoirs. Lithofacies units are characterized by reconciling lithology related attribute data at seismic and well log scales. Reservoir dynamic data are also used to quantify the karst network properties in terms of size, trend and pattern of permeability. With the case study, we demonstrate the application of our new integrated approach to the characterization and modeling of karst networks in the Ordovician carbonate reservoirs. Our results show that quantitative integrated interpretation of karst networks and reservoir architectures can provide a new understanding of carbonate reservoir modeling and underlying geological controls.
Independence Project Completion Campaign: Executing the Plan
Authors: Burman J. W. (Jack) , Kelly G. F. , Renfro K. D. , Shipper D. W.
Published: December 2007

The Independence Project is a world-class subsea tieback development of 10 natural gas fields in the ultra-deepwater of the Gulf of Mexico. Anadarko is presently the operator of eight of the fields, in which 12 wells were pre-drilled to develop the resources. Completion operations began in early 2006 and were finished in early 2007, during which seven single-zone wells, three two-zone intelligent wells, and two three-zone intelligent wells were completed and flow tested from the Transocean Deepwater Millennium drillship.

This paper will document an overview of the Anadarko 10- well completion campaign, during which numerous water depth and completion time records were set, utilizing innovative procedures and downhole designs to safely complete the project significantly ahead of schedule. Rig and BOP modifications, teamwork, effective communication, and novel solutions that positively impacted program effectiveness will be discussed.
Preventing Environmentally Induced Corrosion Cracking by Removal of Thiocyanates from Completion Brines
Authors: Horton Robert L. , Arvie Morris A.
Published: December 2007

While thiocyanates are useful corrosion inhibitors in some low-to-medium temperature ranges, at temperatures of 350°F and upwards, thiocyanates are believed to be prone to thermal decomposition and subsequent environmentally induced corrosion cracking of tubular goods, especially of high strength corrosion-resistant alloys. Stress corrosion cracking has also been postulated to be a risk as a result of hydrogen sulfide production from the decomposition of thiocyanates.

In the life cycle of completion brines, a stock brine is custom-blended with a variety of additives depending on the particular application. In the field, additional components may be introduced, sometimes as contaminants. Once used, completion fluid that is returned to the surface may optionally be subjected to reclamation processes for reuse in a subsequent application. Current API recommended practices specify the testing for such components as solids, pH, and iron; however, it seems reasonable that in the future the recommended practices will also include a specification on the maximum allowable thiocyanate content.

Reclamation processes to date have not focused on the removal of thiocyanates from brines. This paper discusses the laboratory development and field implementation of processes for complete removal of thiocyanates from completion brines before any attempt is made to reuse them. This process works for a wide range of brines, is quite cost-effective, and enables buy-back of used completion brines with only a reasonable additional cost for thiocyanate removal.
Mechanisms and Performance Demonstration of the Gas-Assisted Gravity-Drainage Process Using Visual Models
Authors: Mahmoud T. N. , Rao D. N.
Published: December 2007

The Gas Assisted Gravity Drainage (GAGD) process, developed at LSU, is designed to take advantage of gravity to allow vertical segregation between the injected CO2 and reservoir crude oil due to the difference in their densities. The GAGD process uses the existing vertical wells for CO2 gas injection, and a horizontal well near the bottom of the payzone for oil production.

In this experimental study, a physical model, consisting of two parallel glass plates confining a sandpack, has been used to visually discern the mechanisms operative in the GAGD process. The model was also designed to adopt different vertical well configurations. The model experiments have shown that GAGD is a viable process for secondary and tertiary oil recovery. Oil recovery in the immiscible secondary mode was as high as 83% IOIP and the oil recovery in the immiscible tertiary mode was 54% ROIP. The model has also shown that the gas injection depth may not have an influence on oil recovery as long as there is vertical communication between reservoir layers. The visual model experiments have also demonstrated that GAGD is also applicable in naturally fractured reservoirs. The visual model showed near perfect microscopic sweep efficiency for the miscible GAGD process performed using model fluids.

This paper presents the results of these visual model experiments of the new GAGD process and the various mechanisms responsible for high oil recoveries including Darcy-type displacement until gas breakthrough, gravity drainage after breakthrough, and film drainage in the gas invaded regions.
Effect of Methane on the Global Climate Change
Authors: Bin Dou , Guosheng Jiang , Xiang Wu
Published: December 2007

Methane (CH4) is the most abundant organic compound in the Earth's atmosphere, where it acts as a greenhouse gas and thus has implications for global climate change. In order to completely understand the effect of methane hydrate melting on the global climate change, we present a theoretical study of the climate response to a massive release of methane from methane hydrates. The results showed that the total contribution to the atmosphere from geologicall sources is estimated to be 45Tg CH4 per year, which would result in a further rise in global temperature to induce the destabilization of hydrates. So the destabilization of gas hydrates is likely to be serious hazards in the near future due to the effects of global warming.
Extended Analysis for Gas Condensate Systems
Authors: Hosein Raffie , McCain William D.
Published: December 2007

Equation of State (EOS) predictions for gas condensate systems require extended analysis beyond the heptanes plus fraction. In the absence of experimental data, several schemes have been proposed to extend these compositional data based on the observation that a single straight line relationship exists between log of mole percent and molecular weight for these pseudo-components or Single Carbon Number (SCN) fractions.

An examination of compositional analysis for gas condensate systems showed a discontinuity in the relationship between mole percent and molecular weight at C13. As a result two straight lines are needed for a more accurate description of mole percent; one from C8 to C12 and the other from C13 and beyond. An average absolute deviation of less than 6.0 % between the predicted and experimental mole percent was obtained using parameters from two straight lines. From a single straight line relationship this difference was as high as 36.0 %.

When applied this new universal observation gives an improved prediction of the mole percent of the last fraction. As a result a more accurate description of molecular weight for this fraction can be achieved for use in equation of state predictions. The change in slope at C13 indicates that for gas condensate systems a partial analysis is required up to C12 and splitting schemes can be applied from C13+ and beyond using a single straight line relationship. Beyond C12, experimental data shows that the mole percent of the isomers present are too small to cause any further change in slope.
The Cost of Errors in Estimates Used in Concept Selection
Authors: Jablonowski Christopher J. , Wiboonkij-Arphakul Chaiyaporn , Neuhold Mark Darren
Published: December 2007

This study examines the loss in project value incurred when concept selection decisions are based on erred estimates of input variables. Estimates of the magnitude of such losses are provided, along with an analysis of which input estimates matter most in determining value loss. A procedure for concept selection is defined to model the decision making process and is used in conjunction with a simplified asset development optimization model to estimate project values. The analysis compares project values resulting from concept selection decisions based on erred estimates and decisions based on an alternate hypothesis. Results suggest that cost of erred estimates for initial costs, expansion costs, and the timing of future expansion projects are comparable in magnitude to the cost of erred reserve estimates. Also, the cost of underestimating expected reserve volume tends to be larger than the cost of overestimating reserve volume; aggressive cost estimates are more destructive to value than conservative estimates; and conservative schedule estimates for the timing of expansion projects are generally more destructive to value than aggressive schedule estimates.
A New Thermal Compositional Reservoir Simulator with a Novel "Equation Line-Up" Method
Authors: Huang C. K. , Yang Y. K. , Deo M. D.
Published: December 2007

In a thermal-compositional reservoir simulator, pressures, saturations, temperature and compositions in all the existing phases must be solved. When this equation system is solved implicitly, a system of nonlinear equations results, which is solved by the Newton's method. This requires computation of the Jacobian matrix of partial derivatives. If the appropriate dependent variable is not lined-up with the correct equation, zero pivot elements are generated in the Jacobian matrix. This situation is complicated by the fact that new phases may appear, and existing phases may disappear leading to the type and number of dependent variables changing constantly. Elimination of these zero pivot elements using pivoting is computationally expensive for large matrix systems. In this paper, we present a robust algorithm for lining-up the dependent variables and the equation system appropriately to avoid zero pivots in the Jacobian.

This technique can be applied to the thermal-compositional model with any number of components and phases and there is no constraint on the number of thermal equilibrium relationships. In a system with Nc components and Np phases, and Ne thermal equilibrium constraints, Nc+Np+Ne+2 dependent variables are lined with appropriate equations (pressure and temperature are the two additional variables). Any phase equilibrium calculation (K-value based, equation of state) can be used in this approach.

The motivation for equation line-up and some previous methods are presented followed by a description of the conservation and constraint equations in thermal modeling. A brief description of the simulator framework that allows coupling different physical models and discretization methods is provided. The rules of variable selection for avoiding zero pivots are discussed in detail, including a method to obtain analytical derivatives. As proof of concept, two applications are discussed: a steamflooding example in a fractured system, using the discrete-fracure modeling approach and in situ combustion. A control volume finite-element discretization is used in steamflooding while a finite-difference approach based on the Cartesian grid is employed in the in situ combustion application.
Identification and Classification of New Three-Phase Gas/Oil/Water Flow Patterns
Authors: Keskin Cengizhan , Zhang Hong-Quan , Sarica Cem
Published: December 2007

Three-phase gas-oil-water experiments have been conducted in horizontal pipes at various flow rates and water cuts. Three-phase flow patterns have been observed and identified using a high speed video system and a new classification of three-phase flow patterns is proposed. Twelve new three-phase gas-oil-water flow patterns are: Stratified-Stratified, Stratified-Dual Continuous, Stratified-Oil Continuous, Stratified-Water Continuous, Intermittent-Stratified, Intermittent-Dual Continuous, Intermittent-Oil Continuous, Intermittent-Water Continuous, Annular-Oil Continuous, Annular-Water Continuous, Dispersed Bubble-Oil Continuous and Dispersed Bubble-Water Continuous. The flow pattern maps are presented based on the new three-phase flow pattern classification. Comparisons made with the available two-phase flow pattern model predictions show the inadequacy of the two-phase flow models in characterization of three-phase flow.
Overview of Beam Pump Operations
Authors: Rowlan O. Lynn , Lea James F. , McCoy James N.
Published: December 2007

Beam pumping systems are the most commonly applied worldwide artificial lift method with 59% of all Artificial Lift in North America and 71% of 832000 wells for the rest of the world (World Oil 2000). This paper reviews many of the concerns that operators face when using the sucker rod pumping system. Operational concerns are introduced with a review of the advantages/disadvantages of the system. Automation and Pump-off Control (POC) are discussed. The most commonly automated operating parameters are examined and the technique of configuring POC set points is llustrated. To maintain efficient operation requires that pumping should be done only when the pump has a high percent of liquid fillage. Methodology for designing how to efficiently produce the well by selecting pumping speeds, stroke lengths and plunger diameters is reviewed.

Incomplete pump fillage, tagging on the downstroke, and other downhole conditions contribute to rod buckling and subsequent accelerated rod/tubing wear and possible other damage. Commonly applied solutions such are weight bars and rod guides are reviewed. Dynamometer cards, particularly calculated downhole pump cards are used for diagnostics of problems that exist in a well.

Finally simple best practices are reviewed covering POC's, use of predictive design programs, guidelines for sucker rod applications, downhole pump best practices, surface unit best practices, tubing, gas separation, use of fluid level instruments (fluid shots), effects of casing pressure, and finally some mention of solution to corrosion problems. The paper reviews older practice and suggests newer practice to assist the operator with operational concerns. In general, sucker-rod pumping is the premier method of artificial lift. Many operators will use some other lift method only after justifying why not to use beam lift.
Barriers to Implementation of Real-Time Optimization Technology
Authors: Hite J. Roger , Crawley Charles , Deaton David F. , Farid Kemal , Sternesky Michael
Published: December 2007

The SPE Real Time Optimization Technical Interest Group conducted a survey of its members earlier this year to learn more about the barriers to implementation of this technology. Understanding the barriers better will allow us to focus on the more important issues.

The survey was in two parts. The first asked about the overall process of getting from data to decisions and action. The second focused on the usage of technical and business tools.

This paper summarizes the results of the survey. We found that each step in the process has considerable major and minor barriers to overcome. The most difficult steps were in the areas of business analysis, recommendations / decisions and taking action. These are areas where management can have the greatest impact through improved work processes, governance and procedures. The results also show there is considerable need for improved commercial technical and business analysis tools
In-Situ Residual Oil Saturation Determined at Angsi
Authors: Jakobsson Nils M. , Othman Mohamad , Mansur Hussen
Published: December 2007

This paper describes how an opportunity to determine residual oil saturation in-situ was captured in the Angsi field, a relatively new development in the South China Sea off the East coast of peninsular Malaysia. It describes the data required to determine fluid saturations in-situ in a well drilled through a reservoir which has been flooded by injection water, focusing on the importance of getting representative water salinity and reservoir temperature data. It also discusses how the residual oil saturation (Sor) determined in-situ compares with other Sor estimates.

Residual oil saturation is a critical parameter within reservoir engineering. Sor values are often based on laboratory tests performed on core plugs. Because laboratory Sor data is sensitive to plug heterogeneities and testing method, there is often a high degree of uncertainty associated with such data. More reliable, and more accurate, Sor information can be obtained in wells that have been drilled through flooded parts of the reservoir. Capturing such opportunities requires proper planning and preparation.

At Angsi, such an opportunity was captured during field development drilling. High quality in-situ Sor data was obtained in one of the major oil reservoirs. As a result, the residual oil saturation is now better defined, or less uncertain. This means there is a higher degree of confidence in the reservoir model and production forecasts generated from the model. The importance of reduced uncertainty and a higher degree of confidence in production predictions cannot be overemphasized. Such improvements are key to continued development optimization, and should ultimately lead to accelerated production and increased recovery.
Integrating Pressure Transient Test Data with Seismic Attribute Analysis to Characterize an Offshore Fluvial Reservoir
Authors: Sahni Akshay , Kelsch Ken
Published: December 2007

Interpreting pressure transient tests in complex faulted and stratigraphic environments can be difficult. In fluvial depositional environments, where sand continuity is a significant uncertainty, pressure transient test interpretation can generate several non-unique solutions, all of which may match test data. Using seismic attribute analysis to constrain pressure transient test interpretation leads to better understanding of reservoir heterogeneities and boundaries, and is the central theme of this paper. Additionally, seismic data can guide the design of pressure transient tests, especially the test duration to evaluate key seismic anomalies. Other data such as production history, core data, formation evaluation from well logs, analog information on channel geometry etc. is also important in getting a better understanding of reservoir description. While we briefly discuss all relevant data, the focus of this paper is primarily on integrating seismic amplitude response with pressure transient test interpretation.

The interpretation of the pressure transient test is done numerically, guided by an initial interpretation of point bar and channel system geometry from seismic attribute analysis. The analysis of the build-up pressure derivative clearly shows the impact of point bar boundaries and connectivity across point bars. For the reservoir evaluated, there was fluid and pressure communication across the point bars, and this was reflected in the transient pressure analysis of the build-up and also from historical production data. The results presented in this paper illustrate the value of integrating geology, geophysics and production data with well test interpretation for a fluvial reservoir.
Production Optimization by Real-Time Modeling and Alarming: The Sendji Field Case
Authors: Danquigny Jacques , DaÏan Renaud , Tison Marc , Herrera Ronald , Ndombi Alain-Serge , Valette Pierre
Published: December 2007

Digital technologies can improve oil production and reduce operating costs. In this prospect, TOTAL launched a corporate program called "Field Monitoring" to capitalize affiliate previous experiences. For gas-lifted wells, it resulted in the development of the "Well Performance Monitoring" (WPM) tool which was implemented in December 2006 at the Sendji field located offshore Congo.

This paper presents the main workflows, functionalities and added value of WPM.

Besides multi-real-time data trends, the application offers colour-coded multi-alarm visualization versus time. These alarms are ranked in terms of "priority" and aggregated at each well, platform, field and asset level, allowing well engineers to track down under-performing wells.

Alarms priority can be linked either to well integrity issues or production losses. These real-time estimated losses are computed using network and well modeling softwares; they highlight deviation from optimum operating set points.

WPM makes easier the regular optimization of gas-lift optimization by feeding models inputs with user-validated real-time data.

A major challenge of right-time production optimization is to sustain updated models; two workflows address this issue: automatic modeling of production well tests and real-time modeling of the actual behavior of the production system. When a significant difference occurs between modeling and reality, a specific alarm is triggered.

The present paper shows various examples of enhanced well performance diagnosis and the corresponding production gains. Also, a good support from onsite teams was achieved thanks to key technical solutions such as user-friendly interface, possible individual tuning of each alarm, handling of unstable or unmatched wells. Finally, WPM enables to compute KPI's that allow the evaluation of potential well interventions.

This tool will be deployed at corporate level, and extended to ESP lifted wells, gas injectors or producers and to subsea wells in deep offshore environment. The general alarming, interface features and data architecture will be applied to surface equipment monitoring and optimization.
Reservoir Flow Simulation Using Combined Vorticity-Based Gridding and Multi-Scale Upscaling
Authors: Mahani H. , Ashjari M. A. , Firoozabadi B.
Published: December 2007

A novel technique for upscaling of detailed geological reservoir descriptions is presented. The technique aims at reducing both numerical dispersion and homogenization error, generated due to incorporating a coarse computational grid and assigning effective permeability to coarse grid blocks respectively. In particular we consider implicit-pressure explicit-saturation (IMPES) scheme where homogenization error impacts the accuracy of the coarse grid solution of the pressure equation. To reduce the homogenization error, we employ the new vorticity-based gridding that generates a nonuniform coarse grid with high resolution at high vorticity zones. In addition, to control numerical dispersion, we use Dual Mesh Method (DMM), which uses different grids to solve pressure and saturation equations. The coarse grid generated from vorticity is used for computation of pressure and the reference fine grid is used for updating saturation explicitly. The most strong point of the method is that dual mesh method has been incorporated onto non-uniform grid structure. This combination removes the need to solve the full fine grid for two-phase flow modeling, resulting in a less computationally demanding and more accurate upscaling technique. To evaluate the method, we run two-phase simulation using different 2D test cases. Our results indicate that the non-uniform DMM is more accurate than the uniform DMM due to using vorticity-based grids. The speed-up achieved in the computation is significant depending on the complexity of model and degree of upscaling.