bluuebunny/crossref_metadata_2025_split huggingface dataset:
Nested Gridding and Streamline-Based Simulation for Fast Reservoir Performance Prediction
Authors: Gautier Yann , Blunt Martin J. , Christie Michael A. 
Published: December 2007

ABSTRACT
Detailed reservoir models routinely contain hundred of thousands to several million grid blocks. These models often cannot be used directly in a reservoir simulation because of the time and memory required for solving the pressure grid on the fine grid. We propose a nested gridding technique that efficiently obtains an approximate solution for the pressure field. The domain is divided into a series of coarse blocks, each containing many fine cells, for which effective mobilities are computed. The pressure is then found on the coarse scale. The pressure field within each coarse block is computed using constant flux boundary conditions obtained from the coarse pressure solution. In this way, a continuous but approximate velocity field is computed on the fine grid. The method is similar to the first step in a multigrid pressure solution. Streamline-based simulation is used to move saturations forward in time. The pressure field is periodically recomputed, taking account of the fine scale permeability and saturation distributions. We test the method for a series of example waterflood problems and demonstrate that the method can give accurate estimates of oil production for large 3D models up to 8.5 times faster than direct simulation using streamlines on the fine grid, making the method overall approximately up to 1,000 times faster than direct conventional simulation. The method is thus able to handle multi-million grid blocks problems easily, enabling simulation to be performed directly on detailed geological models. It is a robust alternative to traditional upscaling, since the effects of changing boundary conditions are automatically accommodated.
An Implicit Treatment of Upscaling in Numerical Reservoir Simulation
Authors: Guedes S. S. , Schiozer D. J. 
Published: December 2007

Abstract
In this paper, it is proposed a multi-scale computational model for multiphase flow that implicitly treats upscaling without using pseudo functions. It overcomes some practical difficulties related to the use of the traditional pseudo curves by executing the upscaling and solution processes in just one step and taking into account changes on the numerical model in an adaptive manner.
A Technique for Generating Reservoir Simulation Grids to Preserve Geologic Heterogeneity
Authors: Stern D. , Dawson A. G. 
Published: December 2007

Abstract
To accurately represent the underlying geologic model, simulation models must preserve important geologic features. This paper describes a technique for optimally selecting simulation model layers to preserve the heterogeneity in the geologic model. The technique involves selecting optimal locations for simulation model layer boundaries, and determining the number of layers needed. Starting with geologic model layering, the simulation model is sequentially coarsened by combining layers to give the smallest possible difference between geologic model properties and simulation model properties. As the simulation model is coarsened, calculations of sweep efficiency for unit mobility displacements are performed to determine how many layers are needed to adequately describe the heterogeneity of the fine-scale geologic model. This technique has two main advantages over existing technologies for layer selection: 1) it provides a quantitative method for determining the number of layers required to preserve heterogeneity, and 2) although the objective function is flow-based, it does not require extensive computer resources to solve the single-phase flow equations on the geologic model grid. As a result, it is easily applied to very large geologic models.
Lessons Learned from Over 300 Producing Well Water Shut-off Gel Treatments
Authors: Portwood J. T. 
Published: December 2007

ABSTRACT
The economic lives of many wells are shortened due to the expense associated with handling excessive amounts of water production. Additionally, hydrocarbon production may be restricted as a result of high producing fluid levels that are commonly associated with high water production. Excessive water production in natural waterdrive producing wells usually results from either "coning" through matrix rock or from vertical fractures that extend into and conduct water from an underlying aquifer. Over the past eight years, Chromium III Carboxylate Polyacrylamide gels have been placed into more than 300 producing wells in such a way as to reduce water flow and lower fluid levels resulting many times with increased oil production due to improved drawdown. Typical water shut-off treatments reduce water production 75% to 90% and, depending on the formation and the cause of the water problem, oil production can be increased by as much as 1,000%. Gels have been applied to fractured and matrix permeability reservoirs, and to both carbonate and sandstone formations.
This paper will focus on providing practical polymer gel information that, when used in conjunction with normal operations data, can be readily reduced to practice. Topics to be discussed include candidate selection criteria, job sizing, gel strength, treatment strategies, treatment monitoring and evaluation, risk factors, results and lessons learned. Economic data including project payout, cost per incremental barrel of oil produced and success rate will also be discussed. Case studies will be presented to demonstrate what is actually working in the field and what can be expected from a successful treatment.
Model for Hot Oil Jobs
Authors: Kenyon Douglas E. 
Published: December 2007

Abstract
This paper describes an Excel spreadsheet used to solve a challenging transient heat transfer problem in a well. A large number of unknown temperatures are solved numerically as a function of time on an R-Z grid. Time steps are controlled by a macro and the formulation is fully implicit for numerical stability. The situation modeled is hot oil injection into a well annulus in attempt to warm the tubing, thus melting wax and allowing its removal. Often the tubing is pumped while it is heating. Hot water or wax solvents are sometimes used in place of hot oil. The annulus may be (and often is) partly empty when annulus injection begins. The location of the injected fluid front is determined from annulus injection rate and other well data. When the injected fluid reaches the annulus sump level near the bottom of the well, that sump level rises rapidly because injection rate generally exceeds annulus drainage rate. This rising sump level slows the possible downward advance of injected heat, which may not reach the needed depth. Examples reveal that the injected fluid cools with depth and that may affect job success.
Gas Well Production Optimization Using Dynamic Nodal Analysis
Authors: Bitsindou A. B. , Kelkar M. G. 
Published: December 2007

Abstract
This work presents a numerical algorithm that permits the production optimization of gas wells using the concept of dynamic nodal analysis. By combining the desirable features of nodal analysis, material balance technique and decline curve analysis, the method is able to match the historical performance of the well data. It is also able to predict the future performance of the gas well under the existing condition as well as altered conditions. The proposed technique, which has several advantages over the classical nodal analysis, can be used for the selection of the timing and capacity of surface compressor, the evaluation of the economic viability of a well stimulation, and the understanding of the effect of individual production component on the productivity of a gas well over the life of that well.
Field Reporting Through the Internet
Authors: Boone D. M. 
Published: December 2007

Abstract
There are now a number of new hardware and software tools that can allow us to easily and efficiently report daily production and operational data from the field using the Internet as the communications medium. The Field Data Collection system described in this paper includes a central secured database that is updated via the Internet and would be available to anyone with the appropriate permissions. The system provides all the input and reporting requirements needed by the operators. Anyone with proper permissions can access the data from anywhere in the world through various pieces of equipment including laptops, desktops, handheld PC's, or even from a web-enabled TV.
The paper will discuss the savings that can be achieved with this new field reporting system through a reduction of paper work from field and office personnel and the reduction of costs of managing internal databases and maintaining hardware and software systems. Other advantages include the availability of daily production data in addition to data such as pressures, sales volumes, lift equipment data, and comments. This information is reported in a much more timely manner; within hours instead of days. All of this will result in significantly reduced costs and workload, improved data quality, more detailed and more timely information, which will lead to improved field operations.
High Efficiency Drilling – A Novel Approach for Improved Horizontal and Multi-Lateral Drilling
Authors: Johnson Jack , Schein Gary W. , Moser Terry , Hayes Steven , Liles H. Don , Webb Steven W. 
Published: December 2007

Abstract
This paper describes a novel approach for improved efficiency of drilling horizontal multi-lateral wells in the Austin Chalk formation in the Masters Creek Field of Vernon Parish Louisiana, at TVDs of up to and exceeding 15,000 ft. The typical well drilled in this highly fractured carbonate reservoir consists of two laterals each approximately 4,000 ft. in length. This new approach to drilling with salt water vs. weighted mud was developed because of the extremely high costs of drilling the laterals and, in some cases, not being able to drill the laterals to the desired lengths with mud. Mud losses could be as high as 50,000 Bbls. or more.
This new approach involves the use of high-pressure frac pumping equipment and service iron to provide high rate, high-pressure salt water to drill the horizontal laterals while drilling under a mud cap to maintain control of the well. The high pressure water along with the drilling cuttings are pumped into the fractures of the formation (no fluid returns). This technology has been used on 19 laterals to date and has reduced the costs of drilling these horizontal sections while providing several other advantages. These include less drilling time, lower mud costs, longer mud motor and MWD runs, no lost revenue (as gas is not flared while drilling each lateral), safer operations from a well control stand point since the casing pressure is generally zero psi, and a shorter time flaring the well to a pit until mud production is eliminated so the well can be flowed to production facilities and ultimately to sales.
This paper presents the ongoing results and advantages of utilizing this new approach in drilling these deep high pressure horizontal wells. It also includes the fractured chalk conditions necessary for this process to be successful, the drilling operating pressures and pumping rates used, pumping equipment modification requirements, and cost savings achieved.
Investigation of a New Fracturing Fluid and Conductivity Enhancement Technology on Coalbed Methane Production
Authors: McCabe M. A. , Robert L. M. , Blauch M. E. , Terracina J. M. , Lehman L. V. , Bowles B. 
Published: December 2007

Abstract
Results of recent field trials with a newly developed fracturing-fluid system and liquid surface-modification additive for coating proppant are presented in this paper. The work was performed in the Underpressured Fruitland Coal (UFTC) gas reservoir in the Northern San Juan Basin of Colorado and New Mexico.
This new technology has influenced production in the region. Data of the test-well population are compared to the coal gas and water production from the reservoir. This study identifies and applies the new fracturing system technology for improving production. The results of this study provide information that may apply to other coal-gas reservoirs.
The study group of wells uses hydraulic fracturing treatments consisting of a new low polymer loading crosslinked fluid system with a proppant surface-modification additive. The fluid system has increased crosslinked-fluid viscosity, requiring a lower gelling-agent concentration. A liquid additive that coats the proppant and increases its surface adhesion is added in the blender tub during the treatment. The surface friction between the coated proppant grains resists high flow rates during cleanup. Modifying the proppant also influences the migration behavior and blocking effects of fines (coal and precipitates) within the propped fracture.
A Comprehensive Rod-Pumping Model and Its Applications to Vertical and Deviated Wells
Authors: Xu J. , Doty D. R. , Blais R. , Shahraki A. , Lea J. 
Published: December 2007

Abstract
This paper presents the modeling of a sucker rod pumping system for both vertical and deviated wells. It focuses on the derivation and applicaton of a new set of comprehensive equations that incorporate both the dynamic rod motion as well as the fluid flow through the annulus between the rod and tubing. The mathematical model for a deviated well is developed using the principles of virtual work. Partial differential equations, and their associate boundary conditions, have been derived to describe the dynamic performance of the system in great generality. The model incorporates all system components and most downhole pump inflow conditions. The effect of lateral rod deformation between the couplings is evaluated by introducing effective longitudinal stiffness and by the Garlakin method. The model for deviated wells incorporates not only viscous friction, but also Coulomb friction. The model’ results are validated against actual measured data. Numerous examples are presented to demonstrate the application of the new technique for the design, analysis and optimization of sucker-rod pumped wells, specially deviated wells.
High Volume and Compression Cages for Subsurface Sucker Rod Pumps
Authors: Ivey R. K. 
Published: December 2007

Abstract
Inefficiencies in sucker rod pumping systems due to gas interference are major concerns for petroleum producing companies throughout the world. This paper describes an innovative cage design that is based on years of exposure to sucker rod pump inspection and repair from many varied field conditions and on compression and flow comparison testing. Observance of results obtained from working closely with the Alberta Research Council in Edmonton Alberta on numerous projects specifically related to conventional, thermal, vertical and horizontal sucker rod pumping was also influential. The creative cage design addresses the two features that are absolutely essential to good standing cage performance. These two features are (1) high compression capability and (2) large flow capacity. The equipment used to perform the flow and compression testing allowed actual visual observation. The tests compared many different cage designs and demonstrated how those design differences affected cage performance.
Proppant Conductivity — What Counts and Why
Authors: Lehman Lyle V. , Parker Mark A. , Blauch Matt E. , Haynes Randy , Blackmon Alan 
Published: December 2007

Abstract
The emergence of "accepted" proppant conductivity testing methods has led to much discussion about what is needed to regain high conductivity levels, and several marketing campaigns have been based on these findings. The industry has generally accepted the principle that delivering high conductivity levels in the fracture is key to achieving high production levels. This paper does not refute this point, but modifies it.
This paper presents theory, laboratory data, and case histories indicating that high initial conductivity levels can only gain high initial levels of potential or actual production. For sustained, high production levels, the proppant pack's integrity must be maintained. With time, most proppant packs are damaged by fines migration, gel clogging, and geochemical precipitation. These processes can be abated with various additives and techniques. This paper discusses these techniques in detail and shows case histories in which the techniques proved costeffective in sustaining higher levels of production than those found in comparable wells.
Exploiting a Reservoir, An Evaluation of Recompletions in the Dakota, Wattenberg Field, DJ Basin
Authors: Emrich Clark A. 
Published: December 2007

Abstract
Resurgence in activity has taken place within the Wattenberg Field of the DJ Basin by deepening existing J-Sand completions approximately 100 feet to the Dakota sandstone formation. The deposition of the Wattenberg Dakota is contained in various shoreface environments. Underbalanced drilling has been the common practice in deepening existing wellbores. Once deepening is concluded, the well is completed open hole. Drilling underbalanced has occasionally yielded favorable results producing the well without stimulation. This may be indicative of natural fracture networks related to faulting. Usually an effective stimulation treatment needs to be placed on the Dakota for it to be an economic success. Due to the favorable results of the play, new drill sites targeted for the J-Sand may be drilled to depths of potential Dakota reserves using conventional mud drilling methods. Well logging will determine if there is a viable Dakota formation. If log signatures indicate potential, the wellbore is cased and the zone stimulated. To date, no wells drilled with mud in this case study have produced naturally.
Dakota production in two areas of interest within the Wattenberg field of the DJ Basin was evaluated. Drilling and stimulation procedures were examined. Well productivity was evaluated using the Reciprocal Productivity Index (RPI) method, well test analysis, and core analysis in an effort to determine the least damaging and cost effective method to exploit the Dakota reservoir. The proximity of wells to normal faults, thus possible permeability enhancement due to natural fracture swarms, will be examined in an effort to determine if such geologic occurrences improve the chances of exploiting the Dakota reservoir.
Start-up of a New Generation Mechanised Drilling Package for Platform Drilling Operations : The Brent Charlie – a Step Change in Performance
Authors: Porteous Steve , van Elst Herman , Leil Drew , Shuttleworth Nigel , Hindriks Hendrik 
Published: December 2007

Abstract
In March of 1997, the Brent Charlie NDES (New Derrick Equipment Set) commenced drilling and workover operations on the Shell/Esso Brent Charlie platform. Expectations were very high for this new breed of mechanised drilling unit. The initial performance was disappointing and the anticipated time/cost savings were not realised. The warranted performance could not be achieved and a number of high potential incidents occurred.
A step change in the performance was achieved and the trend of high potential incidents eliminated through the project approach of a dedicated performance improvement team. The participation of experienced vendor representatives on the project team and drill crew input was critical to the success of the project. The follow up of a structured HAZOP analysis of the mechanised functions in the derrick played a major role in the reduction of the high potential incidents.
Specialised crew training to operate this new breed of drilling unit has led to the development of advanced rig training systems. Hands-on training is no longer sufficient. Underpinning knowledge of the fundamental logic system needs to be taught, understood and tested; simulators need to be developed to teach crews the systems and equipment, allowing experience to be safely gained away from the workplace.
This paper presents the Brent Charlie NDES; from the rig concept and initial performance expectations to the experiences as the rig commenced operations. The performance improvement project, including HAZOP study, resulting in restored operational efficiency and confidence in the safe operation of the new rig is presented. Lessons learned, equipment upgrades to the new rig and enhanced crew training is discussed.
Case History: Utilizing 5-1/2" Drill Pipe in a Deepwater Gulf of Mexico Drilling Program
Authors: Jenkins Roger W. , Greenip John F. , Adams Burt A. 
Published: December 2007

Abstract
This paper describes lessons learned while selecting and utilizing a string of 5-1/2" drill pipe with special reduced clearance outside diameter (OD) tool joints in a long-term deepwater Gulf of Mexico drilling program. Actual field data including hydraulic analysis, fishing considerations, trip-speed, and completion uses are chronicled. The paper also discusses using the string of drill pipe to drill inside a 9-5/8" drilling liner along with tieback and completions inside 9-5/8" production casing. Savings associated with using one string of drill pipe are presented. Inspection results and all damages are discussed. A comparison of drilling loads, drilling hydraulics and completion hydraulics is made on this string of specialty 5-1/2" drill pipe vs. standard 5" drill pipe along with a limited comparison to 6-5/8" drill pipe. Running and handling aspects are analyzed and discussed. A specific well that utilized this string of 5-1/2" drill pipe was drilled to below 27,500' MD (25,600' TVD) and is described as the example case for the program.
Applications for an LWD Formation Tester
Authors: Hooper M. , MacDonald C. , Shalhope R. , Boonen P. 
Published: December 2007

Abstract
After a well or a well interval has been drilled, zones of interest are often tested to determine various formation properties such as permeability, fluid type, fluid quality, formation pressure, and formation pressure gradient. Currently wireline formation testers are most commonly used to perform this testing. However, the use of these testers is sometimes limited by high operational costs, risk of tool sticking, and invasion effects on measurement accuracy. In addition, wireline formation tests interrupt the drilling process and can add days to a drilling program.
This paper presents field-test results of a recently introduced Drilling Formation Tester (DFT). This tester is part of a logging-while-drilling (LWD) tool string and uses mudpulse telemetry to transmit real-time formation pressure data to the surface. Data obtained from LWD sensors are used to determine the thickness, depth, and petrophysical properties of the formation at the targeted test site in the well. Multiple pressure tests can be performed in a single bit run, thus providing the pressure gradients useful in determining oil, water, and gas contacts. Tests can be completed in less than 30 minutes, with only minimal interruption of the drilling operation.
The field test results are analyzed with a recently introduced exact solution to the spherical-flow well-test equation with storage and skin. The solution is used to predict formation pressure and permeability from early- to intermediate-time pressure transients. This scope is greater than what is possible with conventional drillstem test analysis models, which do not model the early-time behavior. The new solution permits determination of storage coefficient, skin effect, formation fluid compressibility, permeability, and pore pressure.
This paper will explain the concept and the basic design of the new LWD formation tester system, give examples of its applications, and discuss its advantages over conventional wireline formation testers and drillstem testers.