bluuebunny/crossref_metadata_2025 huggingface dataset:
Layered Waterflood Surveillance in a Mature Field: The Long Beach Unit
Authors: Woodling G. S. , Taylor P. J. , Sun H. H. , Nguyen Q. N. , Brix T. R.
Published: December 2007

Techniques for allocating historical production (oil and water) by layer for individual producers and waterflood patterns are presented. Production splits were approximated from offset injection histories (i.e. spinner profiles, hydrocarbon pore volumes injected, proximity to injection, and injection timing). The techniques presented include the following by layer:Production Gross & Oil Bubble MapsWater Cut MapsInjection Streamline MapsPattern Performance Graphs

The tools are extremely useful and rapid when well counts and production histories are extensive such as in the Long Beach Unit with 1200 wells and 27 years of waterflooding. Reservoir material balance and pressures are not used in the split logic for a well but checked later for each pattern. Predicted splits and water cuts compared favorably with fullfield reservoir simulation results and field production logs.

The allocation logic works in stratified formations where reservoir cross flow is minimal. Shales or other barriers between zones are required. The logic also requires that injection profiles, pressures, and injection-withdrawal ratios remain relatively constant. However, the logic can be applied over incremental time steps to handle dynamic changes in these parameters.
Coning Phenomena in Naturally Fractured Reservoirs
Authors: Al-Afaleg N. I. , Ershaghi Iraj
Published: December 2007

Development of water coning in naturally fractured reservoirs and the issues of critical rates and cone breakthrough times are examined in terms of appropriate reservoir properties. A correlation is proposed to account for fracture acceleration effects in the computation of critical rates and the breakthrough times for uniformly distributed fractures. For a fractured systems with non-uniform fracture distribution, cone development is asymmetrical and the concept of partial completion to prevent coning becomes inapplicable. As such, for heterogeneously fractured reservoirs, estimation of critical rate and breakthrough time requires modeling with an understanding of fracture pattern around the producing wells.
The Effects of Injectant-Enrichment Level on Oil Recovery in Horizontal, Gravity-Tongue-Dominated Enriched-Gas Drives
Authors: Chang H. L. , Lo Tak Sing , Ring W. W. , Weisbrod K. R.
Published: December 2007

Experiments and simulations showed that the oil recovery behavior of horizontal, gravity-dominated, enriched-gas corefloods is distinctly different from that of one-dimensional slim tubes or corefloods. Additional oil was recovered when the injectant was enriched beyond the one-dimensional minimum miscibility enrichment (1-D MME) level. Mechanisms controlling oil recovery at different injectant compositions are discussed.
Vertical Sweep Efficiency and Oil Recovery From Gas Injection in Heterogeneous Horizontal Reservoirs
Authors: Belgrave J. D. M. , Win Than
Published: December 2007

Many field tests have demonstrated that without the benefit of gravity stabilization gasflooding operations usually result in low vertical sweep efficiency due to gravity override. For this reason horizontal or low relief reservoirs, which constitute a large fraction of hydrocarbon bearing formations, are generally not considered to be good candidates for recovery schemes involving gas injection.

A cross-sectional reservoir simulation study was undertaken to investigate the effect of vertical heterogeneity, viscous/gravity force ratio, and perforation thickness on oil recovery from gas injection in horizontal reservoirs. Three types of reservoir systems were considered: (a) homogeneous, (b) deltaic channel sands, represented by vertically decreasing layer permeabilities, and (c) deltaic bar sands, represented by vertically increasing layer permeabilities. The degree of reservoir heterogeneity was systematically varied and characterized by the Dykstra-Parsons coefficient.

For the homogeneous reservoir, vertical sweep efficiency and oil recovery at breakthrough were found to increase with increasing gas injection rates. On the other hand, over most of the ranges of viscous/gravity force ratio and degree of heterogeneity investigated, channel sand reservoirs tended to give increasing breakthrough oil recoveries for decreasing rates of gas injection. Deltaic bar reservoirs exhibited more complex behaviour.

At low heterogeneity levels these reservoirs gave higher oil recoveries at higher injection rates, and reversed this trend as the degree of heterogeneity increased.

Included in the paper are gas saturation breakthrough patterns, which show the influence of geological and operating conditions on the location of uncontacted oil.
Planning a Coiled-Tubing-Conveyed Production Logging Job in a Horizontal Well
Authors: Copoulos A. E. , Costall Douglas , Nice S. B.
Published: December 2007

Planning is an important part of a successful coiled-tubing-conveyed horizontal well production logging job. Close coordination between a multidisciplinary team, including the operating company’s production engineer, reservoir engineer, field supervisor, and the logging and coiled-tubing company representatives is required. Without a proper balance of input from these individuals, conflicts can arise, costly downtime can occur, and data can be lost. To avoid these potential problems, prejob planning should be considered a necessary and cost-effective part of the coiled-tubing-conveyed horizontal well production logging job.

The multidisciplinary team should jointly address reservoir, operational, and production issues. Reservoir issues include reservoir performance, gas-, oil-, and water-contact identification, fault and fracture identification, variations in rock quality, and productivity. The production issues include instrument selection, wellbore trajectory, rig-up technique, and costs, while operational issues include centralization, drag buckling, equipment compatibility, and a variety of miscellaneous on- and off-site equipment checks. By jointly addressing these and other issues with a multidisciplinary team prior to the job, costly downtime will be minimized, and logging objectives will be more clearly defined and easily achieved.
3D Boundary-Element Model for Predicting Performance of Horizontal Wells
Authors: Koh L. S. , Tiab Diebbar
Published: December 2007

Potential benefits in increased productivity and recovery efficiency coupled with advances in drilling and completion technology have roused considerable interest in horizontal well applications. Since horizontal well systems are characteristically less symmetric (compared to vertical ones), and horizontal wells typically penetrate the reservoir more and in paths that are more tortuous, the flow field and pressure distribution created by such wells can be expected to be three-dimensional in nature and thus be more susceptible to irregularities in geometry and other system properties in three dimensions. There is thus a need for developing predictive tools that adequately describe three-dimensional fluid flow through porous media in realistically complex situations. This need represents the main motivation of this work.

Through the years, both analytical and numerical methods have been used to solve partial differential equations governing engineering problems. Analytical solutions are the most desirable since they are exact and continuous. Unfortunately, they can be obtained only for relatively simple and idealized cases. This has led to the development of various numerical methods which are able to solve more complex and realistic problems. The finite-difference and finite-element methods (FDM and FEM) have been the most widely used numerical techniques in general; in petroleum engineering, however, the use of the former is almost exclusive. The boundary-element method (BEM) is an emerging technique that has gained considerable research attention and popularity in recent years. It offers several potential advantages over the FDM and/or FEM, including Lesser modeling effort, due to the reduction of the dimensionality of multi-dimensional problems by one;Greater numerical accuracy, due to its "semi-analytic" nature and the elimination of grid orientation effects and numerical dispersion; andBetter problem representation, due to its ability to conform better to complex geometries and boundary conditions.

The technique has been successfully applied to many diverse fields. It has only been used to a limited extent in petroleum engineering, however.
Non-Darcy Gas Flow: From Laboratory Data to Field Prediction
Authors: Milton-Tayler David
Published: December 2007

The beta factor, or Non-Darcy flow coefficient is the critical parameter in determining the performance of propped hydraulic fractures in gas wells. In addition, non-Darcy effects enter into the analysis of laboratory-derived gas permeametry data, of reservoir core, and its extrapolation to the field.

In this paper, both the beta factor and the Klinkenberg slip constant are investigated. Flow tests under carefully controlled conditions have been completed in consolidated and unconsolidated media. Anomalies in the beta factor can be readily dealt with as far as proppant packs are concerned, but their implications for gas permeametry in consolidated core may be more serious.
Developments for Reducing Natural Gas Treating and Processing Costs
Authors: Leppin Dennis , Gamez J. P. , Meyer H. S.
Published: December 2007

The Gas Research Institute (GRI) has an R&D Program directed towards natural gas processing issues. Of particular interest is research on problems connected with small-scale subquality natural gas processing. Both fundamental, knowledge-building and applied research are carried out.

Processes and hardware developments in gas processing from this program which are at or near commercial introduction are reviewed. Included are the MVC Multivariable Process Control Optimization, R-BTEX process, and lithium bromide (LiBr) absorption chiller applications in gas conditioning. Obtaining significant technical information on performance of new gas processing technology is also an important activity of GRI and selected applications in this are discussed as well. Included in this category are results oftesting of commercial cellulose acetate membranes for CO2 removal from natural gas and field evaluation of Liquid Redox Sulfur Recovery processes.
Protect the Forest With LNG
Authors: Poulallion P. L. , de Abreu Moreira L. A. , Dominguez J. L. R.
Published: December 2007

The temptation to build a gas pipeline in the Amazonic Forest or an electric transmission system is very strong when you have not knowhow or enthusiasm to develop a new technology. Nevertheless, after a long story, the most sympathetic project was achieved to transport Natural Gas from Urucu to Manaus and Porto Velho.

Beyond a sympathetic point of view, it is also possible to get a good benefit in creation of activity for people (labor) and in efficiency of money (rentability).

The project deals with environment conditions and resolves all problems to transport natural gas on ways given by nature (rivers) and takes opportunities to develop a process to match technical specifications and economics.

Protect the rain forest with LNG is to show how human "profitability can be enhanced in tomorrow's environment".

Main points will be discussed: modular Unit for liquefaction versus scale factor; electric driven compressor versus turbines; air cooler versus refrigerated water; light self container barge versus integrated barges for transportation; fractioning with energy recuperation versus simple vaporization.
A Horizontal Well in Gas Storage: A Case Study
Authors: Bergin S. R. , Shikari Y. A.
Published: December 2007

Enhancement of deliverability has always been a top priority for storage field operators. Historically, all available enhancement techniques have been tried, with varying and occasionally negative results. The recent and rapid development of horizontal drilling technologies has given storage operators another method for consideration.

There are several geological and reservoir engineering aspects in evaluating a potential horizontal storage well project. If favorable conditions exist, a multidisciplinary approach is needed for the design and implementation of a successful project. This paper discusses the methodology and results of a successful horizontal storage well project conducted jointly by Oklahoma Natural Gas Company ("ONG") and the Gas Research Institute ("GRI").
Mitigating Horizontal Well Formation Damage in a Low-Permeability Conglomerate Gas Reservoir
Authors: Cimolai M. P. , Gies R. M. , Bennion D. B. , Myers D. L.
Published: December 2007

In the application of horizontal well development to the Cadomin formation in the Deep Basin gas field of west central Alberta, control of formation damage to a low permeability, thin pay reservoir is of critical importance. Under the current fiscal regime the economics of the limited single well reserve potential does not allow for remedial operations after rig release. The horizontal well is, of necessity, the required stimulation to the reservoir and the drilling of the formation is the completion process.

The two primary formation damage mechanisms which must be controlled are aqueous fluid entrainment and drilling fines invasion which are significantly greater concerns in horizontal wells due to the intrinsically deeper reservoir penetration and longer exposure times. From laboratory studies, the Cadomin is undersaturated with respect to the capacity of the formation to retain water. Invasion of the zone by an aqueous phase doubles the irreducible water saturation within the reservoir severely reducing the relative permeability of the matrix to gas. Coupled with the entrainment of drilling fines, permeability can be impaired by an order of magnitude. In engineering for these conditions in the Cadomin, a viscosified clear diesel drilling fluid was designed incorporating sodium chloride as a bridging agent to permit near balanced drilling.

Reviewed in this paper is a case study describing a history of operations to characterize the formation and the field results of two Cadomin horizontal wells drilled with contrasting aqueous and diesel based fluid systems.
The New Keys to Deliverability: Storage, Imports, and Resource Development
Authors: Kaplan S. M.
Published: December 2007

Gas storage and Canadian imports have become key sources of winter natural gas supply for the U.S. The use of storage and imports to meet winter peaks has reduced the importance of domestic deliverability; by extension, this means that a lower level of resource exploration and development will support current and future demand. However, the growing use of storage may lead to price instability and may increase the risk of spot shortages and curtailments during the summer.
Streamlining Gas Production at Low Gas Prices: Activity-Based Costing for the Gas Production Process
Authors: Lechner H. E.
Published: December 2007

This article describes an economic model which allows calculation of the contribution of a single gas well or a single gas field to the overall operating result of a company. Moreover, this system makes it possible to assess various measures taken at an individual gas well or gas field and the respective effects on the company's operating result. It permits fixing of the ‘stars’ and the ‘dogs’ at any market condition and to find not just one but the optimal solution for our producing properties. A cost accounting system for 3 different levels of decision making (production, well, field) was developed based on contributed margins. By applying previous cost information and future cost estimates, this system provides the required data for making sound business decisions. An example describes how this cost accounting system which is based on contributed margins, was applied. Additional options for the application of this system are outlined.
Use of Vogel's Inflow Performance Relation for Coal Wells
Authors: Seidle J. P. , Erickson D. J.
Published: December 2007

Deliverability of coal wells, like conventional gas wells, depends on bottomhole flowing pressure. Because coal wells often produce both gas and water, lowering bottomhole flowing pressure to increase gas rate also increases water rate. Thus, optimization of coal well profitability entails balancing gas revenues and water disposal costs. The present study was undertaken to determine if the relation between coal well bottomhole flowing pressure and gas and water production rates could be described by Vogel's Inflow Performance Relation (IPR). First, simulation studies were done to test the applicability of Vogel's IPR to coal wells. Secondly, productivity of actual coal wells was compared with Vogel's IPR curves.

Productivity of an oil well draining a solution-gas drive reservoir was investigated by Vogel1 using numerical simulation. A total of 21 simulations covering a wide range of oil, PVT properties, and relative permeabilities were made. By using dimensionless pressures and rates, Vogel found well productivity could be described by

(1) q q max = 1 − 0.2 p w f p a v g − 0.8 ( p w f p a v g ) ) 2

where q is oil production rate in bpd, qmix is maximum oil production rate in bpd, pwf is bottomhole flowing pressure in psia, and pavg is average reservoir pressure in psia. Eq. (1), called Vogel's Inflow Performance Relation (IPR), was found to describe simulated well productivity with a typical accuracy of 10%. Errors as high as 20% were noted for simulations of viscous crudes and/or damaged wells with skin factors great than +5. Over the last quarter century, Vogel's IPR curve has been extensively used to predict oil well performance. Because of this success, the question arose as to whether Vogel's IPR could also describe gas and water production from a coal well.
Fracturing Process Control and Automation: Phase 2
Authors: Stephenson S. V. , Woodall E. L. , Donaghe C. D. , Dant R. E.
Published: December 2007

Since the publication of Fracturing Process Control and Automation Phase 1 (SPE 17315), the entire automated and remote controlled fracture stimulation system has been placed into production globally with hundreds of jobs successfully accomplished and documented.

Phase 1 presented the organizational approach to creating the system. Mechanical equipment, computing equipment and software, operating procedures, and documentation requirements were also discussed in the first paper.

Phase 2 of the project involved: (1) a new design concept for a slurry processor, (2) creating software for the central computer in the control and engineering center, and (3) improving the proppant handling equipment. In addition, fluid monitoring systems were developed.

This paper will present the unified automatic fracturing process control system. Comparison of the advantages and disadvantages of automated, semiautomated, and manual systems will be made. The management task for technology transfer from dedicated design team to design and manufacturing staff and from prototype to full production equipment will be examined.
Graphical User Interface for Existing Field Automation Systems
Authors: Glynn C. J. , Crockett J. R. , Smith C. O.
Published: December 2007

Field automation systems provide an enormous amount of information. In older existing systems, this information is presented to the field staff as text. Significant improvements in the staffs effectiveness and efficiency can be achieved by utilizing a Graphical User Interface. However, quantifying these improvements is a difficult task.
Improved Material Balance Calculations by Coupling With a Statistics-Based History-Matching Program
Authors: Hwan R. R.
Published: December 2007

This paper describes a new material balance calculation by coupling a statistics based history matching program with a material balance program. The procedure is to match the historical reservoir pressure data with the calculated pressures obtained from the material balance program – the so-called pressure match method – with the help of the history matching program.

The combination of the history matching and material balance programs proves to be a very simple and powerful tool for material balance calculations. A user who does not know different material balance methods under various reservoir conditions is able to calculate the material balance with great accuracy. This is because the new procedure is based on the pressure match method which is known to be applicable to all types of reservoirs, i.e., oil or gas reservoir with or without gascap and/or aquifer, with accurate results.

In this paper, the calculation of pressure in the material balance method is briefly reviewed and the mechanism of pressure history match is cursorily discussed. Three case studies, comprising an abnormally pressured gas reservoir, a gascap drive reservoir and an aquifer water drive reservoir, are presented to illustrate the use of the new method. The calculation results of these cases are comparable to or better than those of using the material balance program alone. Moreover, the matches were obtained in only a few number of runs.
A Computer System That Determines Optimal Capacity and Recovery for Gas Reservoirs
Authors: Dougherty E. L. , Chang Jincai
Published: December 2007

This paper describes a C-language software system dubbed FIDOS (Field Development Optimization System) that optimizes development and production from one or more gas reservoirs producing through one or more compressor stations. The optimal schedule delivers the economic portion of a requested profile of offtake rate plus spare capacity vs time over a specified planning horizon. In order to base selection of wells or HP increments upon incremental NPV and PVR, a reservoir simulator and an economic evaluator are imbedded in FIDOS. To reduce computing time for the many simulations, the nodal analysis equations that determine deliverability are solved with a specially tailored technique. With more than one compressor station a generalized network flow model is used it-eratively to determine optimal capacity and production at each station. To preserve machine independence Postscript is used to generate mixed graphical/numerical presentations of inputs and results. An example illustrates FIDOS' utility.
Short-Range Multivariate Process Prediction for Use in Automatized Systems
Authors: Durrer E.J. , Somerton W.H. , Mueller T.D.
Published: December 2007

Automatic process control requires the maximum amount of information about the future behavior of parameters that affect the regulated system. For a particular set of processes, formal mathematical relationships describing this behavior can be established. However, certain processes cannot be described by formal processes cannot be described by formal relationships and their analyses must be based on statistical evaluation of their past histories. In the particular case of multivariate processes, particular case of multivariate processes, regression and time series analyses are the two most powerful tools which can be utilized to describe powerful tools which can be utilized to describe their behavior and to project this behavior into the future.

The above techniques were studied using data from a small natural gas distribution system. The natural gas demand for space heating and the prevailing meteorological conditions were prevailing meteorological conditions were recorded hourly for a group of 14 residential homes in Northern California for over a year's time. Statistical evaluation of the data included study of the correlations of precipitation, wind velocity and direction, radiation, relative humidity, and temperature with demand. Temperature and relative humidity showed the best correlation with demand.

Stepwise regressional analysis applied to the parameters and various combinations of them parameters and various combinations of them revealed that mean values or gradients, predominantly of temperature conditions, are needed in predominantly of temperature conditions, are needed in order to stabilize the system and to obtain reasonable predictions. However, due to the averaging propensity of regressional analyses, peak demands are not well predicted. This peak demands are not well predicted. This difficulty is minimized if one uses methods of time series analysis. Various methods for detrending and elimination of periodicities were checked in order to obtain stationary series to which autoregressive spectral analysis can be applied. Linear filters seem to be simple and yet are as powerful as more complicated ones. Of the three powerful as more complicated ones. Of the three algorithms (matrix defactorization and the autoregressive schemes of Hingorani and of Robinson) tested for spectral analytic predictions, Robinson's proved to be the most efficient. This algorithm also has the advantage that, in addition to better accuracy than the regressional analysis only a relatively short record length is necessary. Therefore, for example, no corrections for population growth in the demand are needed. population growth in the demand are needed. In the present application it was concluded that the greater accuracy of the Robinson algorithm far outweighs the additional costs incurred by the lengthier computations and greater complexity of the method over regression analysis.
Fatigue Failure of API 8-Round Casings in Drilling Service
Authors: Payne M. L. , Leturno R. E. , Harder C. A.
Published: December 2007

This paper presents case studies of casing fatigue failures in API 8-Round STC and LTC connections. This mode of failure is unique and unfamiliar to most industry personnel. The failure mode is important because of the inherent cost of casing failures and because fatigue failures most often occur in drilling casings near the surface, thereby exposing operations to severe well control risks. Key considerations in these fatigue failures include casing and cementing design, landing, drillstring/casing interactions, dimensions and gauging of 8-Round connections, casing ovality, and mill and field make-up control. Conclusions from field and engineering data are provided, along with recommendations to eliminate these failures.
Hole-Cleaning Study of Polymer-Based Drilling Fluids
Authors: Zamora Mario , Jefferson D. T. , Powell J. W.
Published: December 2007

A laboratory study was conducted to substantiate the exceptional hole-cleaning performance of "rheology engineered", biopolymer-based mud systems used in Prudhoe Bay, Alaska, horizontal wells. The study focused on the impact of very-low-shear-rate viscosity and evaluated the combined effects of rheology, flow rate, velocity profile, eccentricity, pipe rotation, and inclination on hole-cleaning efficiency.

The study confirmed that the rheological "fingerprints" of the biopolymer fluids provide optimum hole-cleaning and suspension. These benefits were attributed to the time-independent, yield-pseudoplastic behavior not obtainable with traditional viscosifiers. Engineering of the specially formulated biopolymer fluids represents a clear departure from conventional methods and field rheological concepts.

Rheological properties of the drill-in fluids were simulated by solutions of clarified xanthan gum. The biopolymer fluids consistently outperformed pseudoplastic, hydroxyethyl cellulose fluids tested for comparison. Hole-cleaning studies were run on two flow loops; measurements were taken on several types of rheometers to characterize the fluids. Videotape recordings documented the interaction and interdependence among the hole-cleaning parameters and allowed measurement of velocity profiles in tubes and annuli.
Petroleum Applications of Emerging High-Pressure Waterjet Technology
Authors: Iyoho A. W. , Summers D. A. , Galecki Greg
Published: December 2007

The emergence of reliable systems for developing high pressure waterjet (HPWJ) technology during the past few years has created a tool capable of concentrating intense cutting energy over very small surface areas. However, the use of jets at very high pressure (>14,500 psi; 100 MPa) requires sophisticated equipment and an expensive delivery system, with considerable maintenance costs. To over come this problem, recent trends by investigators are to develop systems which combine waterjets at lower pressure (about 5,000 psi, 35 MPa) either with conventional mechanical drill bits, or with abrasive-laden cutting fluids.

Over the past several years, the University of Missouri-Rolla (UMR) has been one of several institutions which have made significant theoretical and experimental contributions to these innovative developments. Applications of this technology for use in horizontal drilling, mining and environmental systems are discussed in this paper. Results show that with the increased reliability of equipment and improved technical knowledge and experience, the emerging technologies of high pressure mechanically assisted and abrasive-laden waterjet tools can be increasingly applied in improving performance for both conventional and the more challenging conditions of horizontal drilling.
Coring Technology for Point McIntyre Wells
Authors: Wylie G. S. , Rathmell J. J. , Tibbitts G. A.
Published: December 2007

Nine wells were cored in Alaska’s North Slope Point Mclntyre field to provide engineering and geological data for oil reserve estimates. The goals for this coring operation were: (1) provide high quality permeability, porosity, and water saturation core data using mineral oil base mud, and (2) achieve 100% core recovery. Low invasion coring methods were used. Coring, core handling procedures, a new core bit, a new mineral oil base coring mud, and a new chemical tracer for the mud filtrate were developed for the Point Mclntyre operation. This paper describes the bit development, coring, and handling procedures. The mud and tracer developments are documented in companion paper, SPE 26326.1

Point Mclntyre’s reservoir is lithologically complex, consisting of high permeability consolidated quartzose sandstone, low permeability highly cemented litihic sandstone, occasional lithic conglomerate, and occasional poorly consolidated quartzose sandstone. Existing core bits were not optimal for low invasion coring at Point Mclntyre. The hard rock low invasion bit developed for the Point Mclntyre project has smaller, more numerous cutters to increase bit stability and eliminate the tendency to cut undergage cores. Coring rates using the new bit were increased in the harder racks. This core bit achieved low mud filtrate invasion in the low as well as the better quality sands.

Bits and core barrel lengths were selected to maximize the core recovery and minimize rig time. Cutting of core plugs occurred immediately upon arrival in Anchorage. The goal was to keep elapsed time as short as possible to minimize tracer diffusion in the core. In the first two wells, core plugs were cut and trimmed both at the well site and in Anchorage to evaluate the time dependence of tracer distribution in the core and effectiveness of preservation methods. Time dependent effects of water saturation and mud filtrate distribution were not observed. Core plugging was moved to Anchorage for the remainder of the project. The coring methods used at Point Mclntyre provided 99.6% recovery, for 3,068 feet cored with less than 2% of the cored interval having significant mud filtrate invasion in 10 md to 2,000 md pay zone intervals. Technology development for this project was accomplished rapidly and was successful. The technology applied here produced high quality data. This enabled the coring program to be reduced with substantial cost savings. Other cost savings were obtained from high quality operational planning.
CO2 EOR Economies for Small-to-Medium-Size Fields
Authors: Flanders W. A. , McGinnis R. A. , Shatto A. G.
Published: December 2007

CO2 projects undertaken in the past have generally been large fields that benefited from economy of scale and substantial remaining life. Future CO2 projects will generally not have these advantages. However, since the CO2 source and distribution infrastructure are in place, many smaller oil fields may be candidates for CO2 enhanced oil recovery (EOR). This paper investigates the economic viability of conducting CO2 EOR operations in small to medium-size fields under today’s market conditions. The evaluation uses actual production data from a representative CO2 project, current costs to equip the field for CO2 operations, and operating costs in the actual range of ongoing projects. Sensitivity to these factors plus depth and porosity acre-feet are discussed. The economic impact of EOR tax incentives are also considered. Each potential EOR project must be evaluated for its specific conditions. Rate of return and cost values cannot be directly applied to other EOR projects, but can be used as a guide to relative profitability.
It's Time to Educating the Supervising Engineer
Authors: Schwartz D. H.
Published: December 2007

This paper covers the education required of engineers who directly supervise technical staff. Why is this training important? What skills are required? What is wrong with the way we are currently training our supervisors? What type of program is required? These questions form the foundation of a study which eventually relied on sources outside of the Petroleum Industry as there had been little published by the industry. In 1987, the National Research Council along with four other prominent groups, formed the Task Force on Management of Technology and published "Management of Technology: The Hidden Competitive Advantage." The study listed eight primary needs for the management of technology and was the catalyst for the growth of an industry aimed at training managers of technology. Using the NRC conclusions as a guide and looking outside of the Petroleum Industry, this paper develops the justification for and approach to educating supervisors of technical staff.
A New, Fast Parallel Simulated Annealing Algorithm for Reservoir Characterization
Authors: Ouenes Ahmed , Saad Naji
Published: December 2007

This paper presents a new parallel simulated annealing algorithm for computational intensive problems. The new algorithm enables us to reduce the overall time required to solve reservoir engineering problems by using the simulated annealing method (SAM). A simple geostatistical optimization problem (variogram matching) applied to two fields is used for illustration purposes. The reduction of computation time starts by optimizing the sequential simulated annealing algorithm. This task is achieved by an efficient coding and an appropriate choice of topology. Three different topologies are used and their effects on the overall run time and the quality of the generated image are discussed. After optimizing the sequential algorithm, the problem of high rejection rate at low annealing temperature is solved by using parallelization. The new algorithm uses, in an optimal manner concurrently many sequential algorithms. The number of concurrent algorithms is adjusted throughout the optimization to increase the acceptance rate with the optimal use of a CPU. The new algorithm was implemented on a CRAY Y-MP with 4 processors. A 50,400 (280x180) gridblock field was used to test the parallel optimization method. The overall run (clock) time was reduced by approximately the number of concurrent calls of the sequential algorithm.
Semianalytic Solutions for a Well with a Single Finite-Conductivity Vertical Fracture
Authors: Blasingame T. A. , Poe B. D.
Published: December 2007

In this paper, we develop a simple, closed form approximation for the Laplace transform solution for the case of a well with a finite conductivity vertical fracture in an infinite-acting reservoir. Our hybrid solution is based on a coupling of the solution for a bilinear finite conductivity vertical fracture model (which does not model radial flow) and the solution for a uniform flux/infinite conductivity vertical fracture (which does model pseudoradial flow). These solutions are readily obtained from the literature.

Overall, we consider our solution to be valid for CfD≥0.5 and we show that our solution gives less than 1 percent error in both pD and p D’ for CfD>2. We suggest that our hybrid solution is not valid for CfD<0.5 and do not recommend its use for CfD<0.5 under any circumstances.

We have verified this solution against four different solutions given in the literature. Each comparison was excellent which suggests that our simplified solution is more than adequate for practical applications. In particular, we provide verification for constant rate and constant pressure production for values of CfD between 0.25 and 10,000. We also show that our solution is capable of producing very accurate derivative functions.

In addition, by reproducing the literature solutions so well, we also verified that individual flow regimes (formation/fracture bilinear flow, formation linear flow, and pseudoradial flow) are all modeled accurately by our new solution.
A Lithology-lndependent Porosity Model Using Three Neutron Measurements: Part II—Applications and Error Analysis
Authors: Oraby M. E. , Wolcott D. S.
Published: December 2007

A lithology independent porosity model, N3LIP, using three neutron measurements, thermal and epithermal neutron porosity and thermal absorption cross section, was developed and presented at the 33rd SPWLA annual logging symposium (reference 1). This model considers any formation, regardless of its mineralogical composition, as two major regions. The first region is the pore space which is filled with fluid, while the second, the matrix, is the rest of the formation. N3LIP deals with the second region, the matrix, as a black box. The model calculates matrix diffusion length, which is the most lithology dependent parameter of a formation, without a need to know its lithological composition. This matrix diffusion length is calculated using two different techniques while iterating on porosity. The final solution, porosity, is deterrnined by analyzing the difference of the diffusion lengths.

In Part I (reference 1), the methodology of N3LIP was described in detail and applied to some artificial logs generated using SNUPAR (reference 2) as a forward model. Here, the applications of this model to actual reservoirs are presented, and an error analysis of the calculated porosity is discussed. N3LIP has been used to calculate porosity in two different types of reservoirs, shaly sandstone and carbonates. The shaly sand reservoirs are Kuparuk in the North Slope and Long Beach in California, while the carbonate reservoir is Sycamore in the Permian Basin.

Due to concerns of the environmental effects on the calculated neutron measurements, especially the borehole rugosity on the epithermal tool, the uncertainty in the calculated porosity using N3LIP in those reservoirs has been studied by applying uncertainties to the logs that have been used. The effect of these uncertainties are presented and discussed in detail.
Reservoir Scale Sandbody Architecture of Pliocene Turbidite Sequences, Long Beach Unit, Wilmington Oil Field, California
Authors: Lowry Philip , Jenkins C. D. , Phelps D. J.
Published: December 2007

This paper presents the results of a characterization of flow-unit geometry in a series of basin-floor turbidite reservoirs. These reservoirs occur in the Long Beach Unit, a mature, densely drilled field in the Los Angeles basin, California. The efficiency and quality of the zonation effort was enhanced by the application of proprietary well log correlation software. This software enables rapid correlation of a large number of wells as well as quantification and visualization of the resultant stratal geometries. At the field-wide scale, sandbody geometry is characterized as laterally offset, en-echelon, lobate units. Dimensions of these sandbodies range from 2-3 miles along depositional strike, to 1-2 miles along depositional dip. Numerous deterministic shales occur within these sandbodies, dividing them into smaller units that are 40-60 ft thick and separated by shales that are up to 5 ft. thick. These smaller sandbodies are lobate in form, but several have a pronounced elongate morphology. Their lateral dimensions range from 0.5-1 mile along depositional strike and 0.5-1 mile along depositional dip. Although the focus of this study was to provide a description of a densely drilled mature reservoir, results from the study reveal qualitative and quantitative insight into the architecture of this commonly encountered clastic reservoir type. Data from these types of field studies may be used to complement outcrop data for use in deterministic correlation or probabilistic modeling of similar reservoirs where the density of well data is much lower.
Pressure-Transient Behavior and Inflow Performance of Horizontal Wells Intersecting Discrete Fractures
Authors: Guo Genliang , Evans R. D.
Published: December 2007

New analytical pressure-transient solutions and dynamic inflow performance equations for horizontal wells intersecting discrete fractures in an infinite reservoir are presented. The horizontal well is assumed orthogonally penetrating multiple identical and parallel fractures. The reservoir containing the horizontal well is bounded by non-flow parallel planes at the top and the bottom. The pressure-transient solutions are derived using the source and Green's functions developed by Gringarten and Ramey, as well as the superposition principle. The dynamic inflow performance equations are derived by applying the derived transient solutions.

The derived analytical pressure-transient solutions may provide a theoretical basis for the analysis of the transient pressure behavior of horizontal wells intersecting discrete fractures. New evaluation techniques may be developed for determining reservoir properties and fracture characteristics from horizontal well testing. The dynamic inflow performance models presents a theoretical tool for evaluating the effects of fractures on horizontal well performance. They are particularly useful in the production modelling of horizontal wells in tight reservoirs with natural or induced fractures.
Core Porosity Measurements Using Gamma Rays
Authors: Bodwadkar S. V. , Reis J. C.
Published: December 2007

This paper discusses a method for measuring the porosities of core or outcrop samples using the attenuation of gamma rays. The method has been experimentally validated against porosities measured with Archimedes’ method on a variety of lithologies and over a range of porosities. The method is fast, non-destructive, and can characterize small scale heterogeneities in porosity. The lithology and fluid saturations must be known, however.
Nuclear Magnetic Resonance of Rocks: T1 vs. T2
Authors: Kfeinberg R. L. , Straley Christian , Kenyon W. E. , Akkurt Ridvan , Farooqui S. A.
Published: December 2007

It has recently become possible to make pulsed nuclear magnetic resonance (NMR) measurements of subsurface geological formations in situ. The longitudinal relaxation time, T1, has long been the parameter of greatest interest to petrophysicists. However modeling shows that T1 measurements are not repeatable when NMR logging tools move past bed boundaries. Therefore measurements of the transverse relaxation time, T2, must be relied upon. Unfortunately, reservoir rocks have properties that make T2 measurements difficult to interpret. We discuss the relationship between T1 and T2, and the measurement conditions for which T2 gives meaningful petrophysical information.
The Importance of the Geological Model for Reservoir Characterization Using Geostatistical Techniques and the Impact on Subsequent Fluid Flow
Authors: Bashore W. M. , Araktingi U. G. , Levy Marjorie , Schweller W. J.
Published: December 2007

Fluid-flow simulation results are used extensively as reservoir performance predictions upon which to base economics for reservoir management decisions. The generation of numerical models for simulation purposes may be easily facilitated by computer-aided algorithms, regardless of the quality of data or input parameters. This study focuses on potentially erroneous conclusions deduced from simulator predictions if the simulation models are built without a sound geologic framework and the incorporation of seismic-based information. Models derived from two different correlation strategies, lithostratigraphic and chronostratigraphic, using well logs only are compared. Seismic inversions are included within the chronostratigraphic framework as a third model type. Histograms of breakthrough times indicate little difference between the well only models of either correlation strategy, whereas water displacement patterns are significantly different. Selection of the appropriate simulation results is closely tied to the reservoir management objective in question. Models which have been conditioned by the seismic pseudo-logs show substantially different results for both breakthrough and displacement distributions, and the spread or uncertainty in breakthrough estimates is greatly reduced compared to the log-only model results.

A cloud transform method with correlated probability fields is introduced for stochastically estimating one model parameter (porosity) from another (impedance). This method allows incorporation of the scatter in the relationship between the two parameters (crossplot).
Maximum Differential Pressure Perforating
Authors: Walker Terry , Brown Jack E. , Briggs George E.
Published: December 2007

Laboratory data and field results have shown that casing perforations are plugged when there is a pressure differential toward the formation at the time of perforating. As a result, there has been a trend toward thru-tubing completions so that the wells can be perforated with a pressure differential toward the wellbore. However, there has been an accompanying sacrifice in depth of penetration because of the smaller charge size, especially in the thru-tubing hollow carrier guns. Also, when the encapsulated charges are used, the casing has to absorb the shock when the gun is fired.

Recently, a perforating system has been developed whereby the deep penetration of the larger charges in casing guns can be combined with the efficient clean-out of the negative differential perforating. In this system each perforation is sealed perforating. In this system each perforation is sealed off from hydrostatic pressure as the gun is fired. The volume inside the gun at atmospheric pressure is sufficient to contain the products of combustion and still give essentially full formation pressure as a differential into the gun. The resulting implosion into the gun insures that each perforation will have maximum capacity for flow or injection. Laboratory and field data are presented showing the benefits of this new perforator. Full allowable wells are being obtained through natural production in many cases. In others lower breakdown pressures, higher injection rates, and more efficient well treatments and sand consolidation jobs are the result.

Introduction

The effectiveness of perforations in oil and gas well casing has been the subject of a number of papers since the introduction of bullet guns in 1932 and of jet guns in 1948. In 1956 Allen and Worzell and Krueger reported the results of perforating Berea sandstone targets with various perforating Berea sandstone targets with various wellbore fluids and pressure differentials. Their data indicated that serious perforating plugging occurred whenever there was a differential pressure to the formation at the time of perforating, especially with mud in the well bore. These plugs consisted of crushed formation, liner particles, jet charge particles and mud. Pressure differentials as high particles and mud. Pressure differentials as high as 430 psi were required to initiate backflow on some of these tests.