bluuebunny/crossref_metadata_2025_split huggingface dataset:
Brine Imbibition Damage in the Colville River Field, Alaska
Authors: Erwin M. D. , Pierson C. R. , Bennion D. B. 
Published: December 2007

Abstract
Early exploration well tests in the Colville River Field (also known as Alpine) drilled with water-based mud systems exhibited unexplainably high near-wellbore residual skin damage documented by pressure build-up testing. Typical formation damage mechanisms including clay reactions, mechanical damage, and gas trapping could not explain the damage.
Between March 1998 and July 2001, laboratory testing determined imbibition-induced water trapping to be the primary formation damage mechanism. Insitu water saturation is significantly lower than the residual or connate water saturation, a condition rarely encountered in the field. Lab tests quantified impacts and identified methods to minimize or eliminate formation damage. This paper documents how successful identification of a unique damage mechanism improved drilling results in a low permeability sandstone.
Even Optimists Should Optimize
Authors: Bratvold Reidar B. , Begg Steve H. , Campbell John M. 
Published: December 2007

Abstract
The industries interest in formal Decision and Risk Assessment (D&RA), including portfolio optimization, over the last few years has been quite amazing and somewhat surprising. Overcoming the barriers to adoption of these methods, including cultural change, continue to amaze even the most devout practitioners. Whether the drivers for accepting change emanate from the changing business climate that has been motivating recent mergers, political risks, a historical record of underperformance or just continued evolution of business practices, the desired objective remains the same - making good investment decisions.
The growing popularity of D&RA - as indicated by the number of SPE sponsored forums and ATWs, alliances and industry courses on the subject and the general uptake of the language, like P10 and P90 - support the increasing awareness of D&RA methods as a mechanism for improving industry performance. The underperformance of petroleum stocks relative to the entire stock market has been cited by several to justify the even greater adoption of D&RA methods. Though artificial bubbles in telecommunications, dotcoms, and energy trading certainly explains part of the underperformance of traditional industry stocks, like petroleum, serious questions remain about the industries' ability to actually achieve the performance in its investments that is promises in its evaluations. The gap between the promises and performances and possible causes for the gap form the foundation of this paper.
As demonstrated by Campbell, Bratvold and Begg,1trying to address complex portfolio issues with approximations may significantly overstate returns and mislead investors into selecting projects and portfolios that fail to deliver the promised performance. In this paper we are extending this work by pursuing the basic question of the impact of individual and corporate risk attitudes in the context of portfolio selections.
We begin by briefly reviewing the basic approach to efficient frontier optimization for portfolio selection. The concept of utility is introduced and it's application for portfolio level decision is discussed. We then introduce the concept of indifference curves which, in combination with efficient frontier optimization, provides an elegant approach for identifying the optimal portfolio for a risk averse corporation.
As in Campbell et al,1 we are addressing the portfolio selection issue with the intent of emphasizing that trying to address complex issues with a na ve or poor understanding of the impact of individual or corporate reaction to risk, may lead to overoptimistic expectations and subsequent failures to deliver on commitments.
Assessing the Kinetics and Capacity of Gas Adsorption in Coals by a Combined Adsorption/ Diffusion Method
Authors: Siemons Nikolai , Busch Andreas , Bruining Hans , Krooss Bernd , Gensterblum Yves 
Published: December 2007

Abstract
Storage of carbon dioxide in geological formations is for many countries the only option to reduce greenhouse gas emissions and thus to satisfy the Kyoto agreements. The CO2 storage in unminable coal seams has the advantage that it can sequestrate CO2 emissions from industrial processes and be used to enhance coal bed methane recovery (CO2-ECBM). For this purpose, the storage capacity of coal is an important economical parameter.
An experimental set-up has been developed to determine the rate of adsorption of gases such as carbon dioxide and methane in coal. Sorption kinetic experiments were carried out at various pressures and on coal particles with varying grain sizes (40μm-2mm diameter). The particles were considered to consist of aromatic aggregates embedded in amorphous aliphatic coal, intersected by cleats. The characteristic time of adsorption increases with increasing pressure and increasing particle diameter. However the characteristic time increases only for very small particles. This is attributed to the presence of cleats inside the larger particles. From the experiments it appears that water inhibits diffusion due to its presence in the small particles or in the small cleats. The results of the diffusion experiments can be described by an upscaled diffusion -adsorption model. Based on this model and the experiments an accurate assessment of the storage capacity can be achieved.
Liquid Management on Canyon Express
Authors: Cooley C. , Wallace B. K. , Gudimetla R. 
Published: December 2007

Abstract
The Canyon Express (operated by Total E&P USA Inc.) subsea development consists of 10 subsea wells each tied into one of two 57 mile, 12" flowlines, that extend from the deepest wells at 7250 foot water depth to a shallow water host platform at 300 foot water depth. Although the production is a relatively dry gas, there exists some volume of liquid that returns to the platform with the gas as a result of produced liquids and return of methanol injected for hydrate remediation. Because of the extreme lengths and depths of the Canyon Express flowlines liquid management has been a significant concern with extensive transient and steady state analysis being performed throughout the project design phase to evaluate the behavior of the liquid in the flowlines. Complex transient flow models, including flow line and topside facilities characteristics, were developed and numerous simulations executed to determine the optimal and feasible operation for the multiphase fluid Canyon Express flowlines under various conditions during field life. During start up and the early operation of the Canyon Express system the actual results for liquid holdup and flow were documented for various well ramp-up scenarios. The purpose of this paper is to compare results from the design phase for liquid management on Canyon Express with actual operating conditions and summarize the evolution of the current operating philosophy. The original transient and steady state analysis will be compared to the actual conditions experienced in the operation highlighting lessons learned in flow modeling and other assumptions made. This paper will demonstrate the usefulness of extensive transient and steady state analysis on projects with complex flow conditions and the importance of incorporating the conclusions of the analysis into implementation plans that can be subsequently adjusted to reflect the actual field conditions.
Measuring Interactions of Dynamic Fluid Mixing and Heterogeneity for Gas EOR Processes
Authors: Lee Sheng-Tai , Moulds Tim P. , Solano Reinel , Lin C. Y. , Ballin Paulo R. 
Published: December 2007

Abstract
Sweep efficiency is a key subsurface parameter that determines the economic viability of miscible-injectant (MI) EOR project. It is controlled by interactions of fluid mixing and heterogeneity on the reservoir scale. We propose a method to measure the sweep efficiency for MI EOR projects. Our method involves using fine-grid two-component miscible reservoir simulation, combined with a one-dimension convection-diffusion model, to determine effective parameters that control reservoir-scale mixing.
We demonstrate the applicability of the proposed method by performing the miscible simulations for 5 type-pattern models (TPM's) of the Prudhoe Bay Miscible Gas Project. The EOR oil recoveries, calculated by fine-grid EOS compositional simulations, for the 5 TPM's are shown to correlate consistently with the effective macro-dispersivity determined through the analytical one-dimension convection-diffusion model. The effective macro-dispersivity, obtained through the proposed method, therefore can be used to measure the effect of heterogeneity on sweep efficiency and to rank reservoirs for EOR applications. The established trend then allows us to investigate different realizations of reservoir description on the EOR oil recovery with substantial saving of time. Our results also indicate that a consistent method must be used to develop reservoir descriptions when comparing and ranking sweep efficiencies for different reservoirs for an EOR project.
Compositional Upscaling in Heterogeneous Reservoirs: Effect of Gravity, Capillary Pressure, and Dispersion
Authors: Ajose D. , Mohanty K. K. 
Published: December 2007

Abstract
Effect of a fractured zone on transport of gas-condensates during lean gas recycling through an otherwise homogeneous medium is studied here. Transport of components is upscaled by the alpha factor method for a single-porosity, coarse-grid model. Fine-grid discrete fracture model is used to simulate primary drainage followed by lean gas recycling. Fracture orientation, gravity and capillarity affect alpha factors significantly. Horizontal fractures have lower alpha factors than vertical fractures. Down dip injection increases alpha factors. Capillarity increases alpha factors. Diffusion does not affect alpha factors at the scale studied. Three-dimensionality of the fine-grid simulation decreases alpha factors over those calculated with two-dimensional simulations.
A Two-Level Optimization Method for Geostatistical Integration of Production Data on Non-Uniform Grids
Authors: Tureyen Omer Inanc , Caers Jef 
Published: December 2007

Abstract
Fine scale heterogeneities can have significant effects on flow performances in subsurface formations. Highly detailed geostatistical realizations are needed to capture the quantitative effects of these heterogeneities on flow simulation results based on high resolution well-log and medium resolution seismic data. These realizations in many cases require number of grid cells on the order of 106-107, hence making it too demanding CPU wise to directly history match geostatistical models. Non-uniformly gridding these models for emphasizing the heterogeneities does not necessarily present a solution since the practice of geostatistics on non-uniform grids is inefficient.
In this paper we provide an entirely new approach to these problems by proposing a solution which is geostatistics based yet having the flexibility to work on non-uniformly gridded models. Hence coupling geostatistics with non-uniformly upscaled models results in an effective history matching technique incorporating all information at their scales. With the proposed approach we mainly target three advantages. Well and seismic data will still be effectively incorporated in the realizations. Flow simulations will be performed on non-uniformly upscaled models hence will be relatively fast. Finally the resulting field which is history matched will include the geology and will be on a non-uniformly gridded model for emphasizing heterogeneities or desired specifications, hence future predictions can be made fast, no posterior upscaling is required. The latter will avoid upscaling errors.
This new approach is based on making a fast non-uniform upscaling technique a part of the history matching process instead of performing upscaling first and then downscaling again. Two levels of optimization are introduced in this technique; one level for history matching (outer loop) and the other for optimizing the non-uniform grids based on the results of a fast but realistic flow response (inner loop). In this paper we show how we benefit from a pre-optimized solution in conditioning reservoir models to production data.
Use of PEBI Grids for a Heavily Faulted Reservoir in the Gulf of Mexico
Authors: Melichar Herbert , Reingruber Alan J. , Shotts Douglas R. , Dobbs Walt C. 
Published: December 2007

Abstract
Creation of a simulation grid that accurately represents the reservoir and enables efficient numerical solutions is often one of the most important steps in constructing a reservoir simulation model. Complex structural settings can present particular challenges in this respect. This paper demonstrates a novel approach to this problem: the use of PEBI grids, which are unstructured and extremely flexible, with a commercial reservoir simulator that was designed primarily for structured Cartesian or corner-point grids.
This unconventional combination of techniques is accomplished without a significant change in workflow. The PEBI grid – a combination of Cartesian and irregular grid blocks – is first built to represent the necessary geologic and well detail. Then the grid is made compatible with a conventional reservoir simulator by treating the irregular parts of the grid as non-standard gridblock connections to their neighboring Cartesian blocks.
The business example comes from a development study of a highly faulted reservoir group located in the Gulf of Mexico. Associated structural complexity includes steeply dipping beds, sloping, directional wells cutting through faults, and interbedded shale layers. A comparison of simulation results from PEBI and conventional rectangular and curvilinear grid-based models illuminates the advantages of PEBI grids for this project: a more accurate representation of geologic detail with less effort, more computational stability, and reduced cycle times for model updates following geologic model revisions.
Identification of Tidal Signal in Well Test Pressure Data
Authors: Levitan Michael M. , Phan Vinh 
Published: December 2007

Abstract
The bottomhole pressure measurements acquired during well tests sometimes contain oscillating components associated with tides. When present in well test data, tidal pressure oscillations may mask reservoir related transient pressure behavior. Hence, from pressure transient analysis point of view the tidal signal is a parasitic feature that has to be identified and removed from the test pressure data. At the same time, the tidal signal itself depends on formation properties. For example, amplitude of tidal oscillations depends on formation compressibility. Therefore, identification of tidal signal in downhole pressure data provides a means for monitoring the reservoir compressibility changes associated with reservoir fluid movements and long-term production.
Compared to the pressure variation during a well test, the amplitude of the tidal pressure signal is normally very small. This makes it very difficult to identify the tidal signal in the test pressure data. In this paper, we present a special algorithm for identification of tidal signal in downhole test pressure data.
Horizontal and Deviated Wells Water Disposal Injection Experiences in a Venezuelan Heavy Oil Reservoir in the Orinoco Belt and Future Injection Practices
Authors: Briceño M. C. , Peralta J. A. , Silva R. J. , Rismyhr O. , Zerpa L. B. , Ehlig-Economides C. A. 
Published: December 2007

Abstract
Data acquired from permanent pressure gauges over 2 years in a water disposal wells in the Zuata Field, Orinoco Heavy Oil Belt, has revealed significant injectivity declines. Pressure transient analysis over the entire period on a flow period by flow period basis is complicated by severe fluctuations in the injection rate during injection flow periods and rarely analyzable falloff periods. Injectivity is inhibited by large skin at all times. A very strong correlation between injectivity index and skin was determined from pressure transient analysis, which also provides a very high value for the rock permeability thereby quantifying the very high theoretical injectivity expected in the wells.
Several hypotheses are considered in order to explain the steep decline in injectivity decline. One of the hypotheses was sanding because it occurred in one injection well when it was shut in quickly and/or under severe fluctuations in rate. Another hypothesis is formation plugging. One possible cause for formation plugging may be a salinity contrast between the injection water and the original formation water, which could activate clay swelling. A second possible cause is formation damage caused by solids and/or organic contaminants in the injection water.
In addition to investigations to evaluate the various hypotheses to explain the injectivity decline, a decision was taken to try horizontal injection wells, also equipped with permanent pressure gauges, and in addition, distributed temperature surveillance via fiber optic installed along the entire drilled length of the well.
The data from the various wells equipped with permanent pressure gauges and distributed temperature surveillance was augmented by core analysis and laboratory studies of the injection water. The analysis has indicated which the main causes of the injectivity decline are, and measures are being taken to correct the problem.
Using Multiple Reservoir Measurements to Improve Subsurface Description in Deepwater Gulf of Mexico: King Field
Authors: Haddad Sammy , Simms Gerard , Clerk Colin 
Published: December 2007

Abstract
King Field is located in the Deepwater Gulf of Mexico (GOM) about 110 miles SE of Venice, Louisiana in Mississippi Canyon blocks 84, 85, 128, and 129 (Fig. 1). The main sand, the Upper Miocene 70 (UM 70), is an undersaturated oil reservoir. The sands were deposited by gravity flow processes within an intraslope basin. The formation is highly porous and permeable (31%, 1000md). Lateral and vertical heterogeneities identified by seismic amplitudes and Amplitude Versus Offset attribute analyses have been confirmed by, and calibrated to, well logs, cores and flow tests. Sedimentary facies studies have shown that at least two different styles of deposition are present; lower massive sheet sand, and an upper sand which is more variable and probably channelized. The trap is a three-way antiformal closure against a major fault with a hydrocarbon column of 1400 ft. Fig. 1King field location map.
Permeability and pressure data were obtained from core, nuclear magnetic resonance (NMR) measurement, MDT* Modular Formation Dynamic Tester, closed chamber, flowback and recent permanent gauge data. This paper compares and demonstrates the utilization of results from each source of measurement on different wells. Differences and agreements of these data are discussed.1
This work demonstrates the use of these data to define a geologic model and better predict well productivity and reservoir continuity. Lessons learned from integrating these multiple sources are summarized.
Comparison of Two Low-Permeability Horizontal Devonian Projects in the Permian Basin with Competing Completion Techniques
Authors: Edgeman J. R. , Walser D. W. 
Published: December 2007

Abstract
Detailed production data from 32 horizontal Devonian wells in the Permian Basin was studied to determine if the impact of various completion methods might be distinguished from an existing reservoir overprint. Flowing transient pressure analysis was utilized to determine effective permeabilities, contributing lateral lengths, and respective drainage radii. Production and economic performance on each well were normalized for permeability, productive zone height, porosity, and initial static reservoir pressure, so that examinations into various completion processes would be more meaningful. Multiple physical parameters and controllable process variables were then plotted versus normalized net present value.
A fully coupled three-dimensional reservoir and wellbore simulator was employed to match historical results and extrapolate conclusions beyond the narrow confines of the two projects.
Some wells in the study were completed with cemented liners, and others completed with pre-drilled uncemented liners. A direct comparison is made between the two completion styles.
Case History of Hydraulic Fracture Performance in a Channel Reservoir
Authors: Liu Xinghui , Cipolla Craig L. , Mayerhofer Mike 
Published: December 2007

Abstract
This paper presents a detailed case history of hydraulic fracture performance in exploratory gas wells in the Hanoi Trough, Vietnam. The target formations are stacked fluvial channel deposits that occur at depths of 10,000 to 12,000 ft. The target D14 interval consists of low permeability, over-pressured gas reservoirs. The wells were fracture stimulated in an attempt to improve deliverability. This paper provides a brief summary of previous fracture treatments, but focuses on the fracture design, execution, fracture modeling, and post-treatment reservoir & production analysis from the most recent fracture treatment. A comprehensive data set of logs, pre- and post-fracture pressure buildup tests (PBU's), and detailed fracture modeling was utilized to understand fracture performance in this complex channel reservoir environment. This paper documents how an integrated study can be used to identify channel reservoir shape/size, understand fracture performance, and optimize fracturing treatments & reservoir development.
Operation of Ultra-Deepwater Gas Wells With Failed Down Hole Gauges
Authors: Sutton Robert P. , Guillory Terry L. , Cox Stuart A. 
Published: December 2007

Abstract
This paper provides a case study of Marathon's Camden Hills gas field, located in world record water depth of over 7,200', in Mississippi Canyon Block 348. Two wells were completed and tested during late 2001 and the first half of 2002. The down hole pressure/temperature gauges failed in one of the wells as it was being unloaded and tested, only providing a static bottom hole pressure. The other well was unloaded and tested, and the down hole gauges provided valuable information about reservoir and completion performance parameters. Prior to production startup in the fourth quarter of 2002, the second well's down hole gauges failed.
Prior to production start-up, well performance models were constructed for each well utilizing the limited data obtained prior to downhole pressure and temperature gauge failure. Operational procedures were developed to provide a methodology for acquiring data necessary to quantify well performance. The master MCS for the subsea system, located at the host platform gathers electronic data received from the wellhead pressure/temperature sensors and the multiphase flow meter. This data is transmitted into an internet web site allowing all participants access to real time data. This data is then input into the prediction models so performance can be monitored and updated. The Gas Production Analysis (GPA) technique was utilized as a further check of reservoir and well performance. Successful implementation allowed the well's performance metrics to be monitored and adjusted to maximize withdrawals while minimizing the potential for premature failure.