bluuebunny/crossref_metadata_2025_split huggingface dataset:
Permeability Determination from Stoneley Waves in the Ara Group
Authors: Qobi Latifa , De Kuijper Andre , Tang Xiao M. , Strauss Jonathan , Munkholm Mette 
Published: December 2007

Abstract
Measurement of continuous permeability profiles on a routine basis has become possible through recent advances in wireline logging hardware and software. Continuous permeability profiles allow geologists, and reservoir engineers to better characterize their reservoirs and to more efficiently complete and manage the production of the hydrocarbon reserves. One of the most promising methods for the calculation of continuous permeability information is the use of Stoneley wave data acquired using a monopole acoustic device.
This paper presents the results of a case study conducted for Petroleum Development Oman (PDO) in which permeability is determined from Stoneley wave data for two wells, namely Sarmad-1H2 (SAR-1H2) and Sarmad-2H1 (SAR-2H1), penetrating the carbonate reservoirs of the Ara group in Oman. The objectives of the study are: To demonstrate the validity of the methodology.To test whether this method can be used on a routine basis aimed at obtaining a continuous permeability index for completion evaluation purposes.
The Stoneley wave derived permeability profile is compared with permeability data from other sources, such as, core data, wireline pressure tests, and interpretation of nuclear magnetic resonance measurements.
The results of this case study clearly demonstrate the great potential of using Stoneley wave for permeability prediction.
Applications of a New Multiple Sensor Production Logging System for Horizontal and Highly-Deviated Multiphase Producers
Authors: Chace David , Wang Jianrong , Mirzwinski Roman , Maxit Jorge , Trcka Darryl 
Published: December 2007

Abstract
This paper focuses on the first applications of an improved, second-generation multiple sensor production logging system designed for use in horizontal and highly deviated multiphase producers. The system integrates several key measurements to provide a comprehensive analysis of well performance under a variety of conditions and flow rates. An expanded and improved 2-dimensional capacitance array is used to define flow regime and measure 3-phase holdup, velocities and flow rates. A new 3-detector pulsed neutron instrument provides an independent measurement of water velocity, 3-phase holdups, and formation water saturation. Auxiliary sensors include an acoustic transducer and distributed temperature sensors useful for gas entry, liquid entry, and behind-casing channel identification. A quartz-pressure gauge measurement is recorded which is also useful in mechanistic models of multiphase flow.
While a brief description of the system components will be provided in order to familiarize readers with the measurement concepts, this paper will concentrate on field examples from the Middle East that demonstrate the first use of the improved logging system in horizontal openhole multiphase producing wells. Determination of multiphase holdups, cross-wellbore velocity profiling, and production inflow profiling is demonstrated. Openhole logs are also shown, including resistivity image data, which clearly differentiate the inflow points as producing bed layers or conductive fractures.
Three Successful Large-scale Field Tests of Crosshole Electromagnetic Tomography Technology
Authors: Zeng Wenchong , Zhao Wenjie , Wilt Michael 
Published: December 2007

Abstract
A leading edge for the applied technological development of geophysics today — crosshole electromagnetic (EM) tomography technology, is an extremely challenging research topic. Its principal technological objective is to realize the direct measurement of the interwell resistivity in order to offer a two-dimensional, even three-dimensional resistivity image reflecting formation structure, reservoir property and the distribution of oil, gas and water between wells. So it not only is a momentous development of the conventional logging technology, but also will revolutionize the reservoir research. Shengli Oilfield (or SPAB) has cooperated with EMI to conduct the application study of the crosshole EM tomography technology for many years. Recently five large-scale industrial tests of the crosshole electromagnetic tomography were conducted successfully in three pairs of wells in Gudao and Chengdong oilfields attached to Shengli Oilfield. The desired results are achieved in three tests. Not only the stability and reliability of the instrument performance are proven, but also it is the first time in the world that a complete measurement data with good repeatability and high accuracy has been obtained when the interwell distance is up to 433.6 m for openhole to openhole and 147.19m for openhole to steel-cased hole. The resistivity image obtained from the inversion has provided a good geological result in analyzing the interwell hydrocarbon and sand body distribution. These achievements indicate that great progress has been made in the industrialization of the crosshole EM tomography technology.
Waterflood Management: A Case Study of the Northwest Fault Block Area of Prudhoe Bay, Alaska, Using Streamline Simulation and Traditional Waterflood Analysis
Authors: Grinestaff G. H. , Caffrey Daniel J. 
Published: December 2007

Abstract
This case study of a complex multiple-Zone waterflood in Prudhoe Bay, Alaska, focuses on the basics of waterflood management that are often overlooked. Evaluation of injection well conformance, flood front behavior, and reservoir description, followed by improved injection well management resulted in dramatic improvements in waterflood performance.
Assurance of waterflood performance requires an integrated approach and accurate performance predictions. The performance of the Northwest Fault Block (NWFB) waterflood was analyzed with traditional decline curves, Hall plots, and a thorough review of well histories to ascertain that it was under performing. A high-resolution 3-D streamline model proved to be the simulation of choice to answer regional and individual well performance questions for this complex waterflood. After achieving a history match for each of the 200+ wells, streamline modeling provided accurate results of vertical and area wide sweep inefficiencies that were later verified by horizontal drilling. Water cycling was quantified by streamline simulation and injection reduced by 30-40%, resulting in increased production and cost savings. Expansion of the waterflood into the gravity drainage area was stopped. Most importantly, bypassed oil is being developed through an aggressive injection well replacement program.
These promising results were achieved by a multidisciplinary team that focused on understanding micro and macro scale reservoir mechanisms. This holistic understanding of mature waterflood behavior, was achieved with a thorough understanding of injection well behavior and streamline simulation at a detailed scale to match each wells performance.
Application of Radial Flow Theory and PLT Surveys to Determine Reservoir Pressure and Wellbore Conditions for Gas Reservoirs
Authors: Wang Shie-Way 
Published: December 2007

Abstract
This work presents a new method to determine average reservoir pressure, change of wellbore condition, and skin factor based on (1) pseudo steady state or steady state theory, and (2) flowing bottom hole pressure and production rate obtained from production logging tool surveys for a single or stacked-pay reservoir. This new method requires two production rate perturbations at 24 hours apart and is equally applicable to oil reservoirs. Four examples are provided to demonstrate how to apply this new method. A single reservoir with multi-layers in vertical communication was used in examples 1 to 3. A stacked-pay reservoir was used in example 4, which consists of six sand-shale sequences with different net pay, permeability, and skin factor for each sand. Excellent agreement is observed in all examples between calculated reservoir pressure and skin factor and those obtained by reservoir simulation.
Gas-Condensate Well Test Analysis With and Without Relative Permeability Curves
Authors: Penuela Gherson , Civan Faruk 
Published: December 2007

Abstract
Based on an analytical analysis of the steady-state theory and its application to well test interpretation in gas-condensate reservoirs, two simplified models are proposed when relative permeability curves are not available. They allow the reservoir engineer to have relative permeability curves as functions of bottomhole pressure from constant composition experiments. Step-by-step procedures explained in the paper rely on the suitability of the steady-state assumptions. Comparisons are made using actual field data and discussions on applicability are also presented. One of the methods is applicable when very low capillary number can be assumed, and immiscible relative permeability curves can be used for pressure transient interpretation. This method is recommended to be used in pressure buildup data analysis. The other proposed method is recommended for pressure drawdown data analysis and is based on the assumption that miscible flow regime controls the fluid flow in the near wellbore region. It is concluded that, although it depends on several factors, miscible relative permeability curves are generally good approximation for pressure drawdown data analysis.
An additional method is also discussed. It relies on the ability to simulate properly the near-wellbore fluid flow with accurate fluid and flow models. Using output data from a compositional simulator, it was shown that it is possible to numerically model fluid bank impairment, while analytically, it is possible to obtain reservoir properties, usually shadowed in current methods for condensate buildup.
The proposed numerical method requires detailed information and can be impractical to apply at early stages of gas-condensate production. On the other hand, the two analytical methods are shown to give good estimates of permeability, mechanical skin factor and reservoir initial pressure at early stages when relative permeability data are not available or are not sufficiently reliable.
Matching Production Rates From the Saih Rawl and Barik Gas-Condensate Fields Using State-of-the-Art Single Well Reservoir Simulation Model
Authors: Skaar Rolf G. , Walpot Kimberly S. , van der Post Niko 
Published: December 2007

Abstract
This paper describes how the initial 6 months of production data from the Barik and Saih Rawl gas condensate fields was matched in state of the art single-well-simulation models. A total of 10 wells were matched and very good agreement between the simulated and actual data was obtained. Detailed results are presented for 3 of the 10 wells. The results from reservoir simulation also agreed favourably with results from analytical well test analysis. The production wells in the two fields described have been stimulated with either single or multiple, propped hydraulic fractures.
Impact of Rock Plasticity on Hydraulic Fracture Propagation and Closure
Authors: Dam D. B. van , Papanastasiou P. , de Pater C. J. 
Published: December 2007

Abstract
We performed scaled laboratory experiments of hydraulic fracture propagation and closure in soft artificial rock and outcrop rock samples. We also performed numerical simulations of the fracture behaviour in plastic rocks, using independently measured rock properties. The simulations aided us in interpreting the measurements and extrapolating the results to field scale. Plasticity induces a larger width for a given net pressure, compared with elastic rock. However, the pressure to propagate fractures is only marginally increased and in the case of the laboratory tests was actually lower than expected from elastic behaviour. The most dramatic effect of plasticity is that closure is much lower than the confining stress due to strong stress redistribution along the fracture.
Modeling of the Acidizing Process in Naturally-Fractured Carbonates
Authors: Dong C. , Zhu D. , Hill A. D. 
Published: December 2007

Abstract
When a naturally fractured carbonate formation is treated with acid at pressures below the fracturing pressure, the acidizing process will likely be different from either a matrix treatment or an acid fracturing treatment. Our previous experimental study shows three kinds of acid etching patterns after acidizing naturally-fractured carbonates and also illustrates their relationships with the fracture properties and acidizing conditions. Based on the experimental observations, a mathematical model of acidizing naturally-fractured carbonates has been developed. The model includes bulk solution transport, acid transport and reaction, and the change of fracture width by acid dissolution. A new approach was used to treat leakoff acid and acid-rock reactions at the fracture walls. The new acidizing model for numerically generated rough-surfaced fractures predicts the same kinds of acid etching patterns and the same relationships between acid etching patterns and the fracture width, surface roughness and leakoff rate as observed in experiments.
Development of a Type Curve to Locate Partial Blockages in Gas Flowlines
Authors: Liu Liangjian , Scott Stuart L. 
Published: December 2007

Abstract
As exploration and production operations move into deeper waters, producers are faced with new flow assurance challenges. One problem associated with deepwater production is the deposition of paraffins, asphaltenes, hydrates, and scale within the pipeline. These depositions form partial pipeline blockages that reduce flow capacity and may ultimately put the subsea flowline at risk. Pigging and other intervention techniques can be used to deal with this problem. This paper develops a method for locating partial gas pipeline blockages and estimating their size. This method can be used to provide important information for monitoring chemical inhibition programs, scheduling pigging, assessing risk for pigging and planning other intervention procedures.
The type curve model is based on the pressure transient analysis of a shut-in test. It can locate the blockage when the blockage size (represented by a blockage factor) has been determined by the backpressure technique. A new average pressure model has also been developed. This method can also be used to locate a partial blockage by examining differences in the average pressure that is measured when a flowline is shut-in at both ends.
Critical Flow Rate for the Buckling of Nonrotating Drillpipe Conveying Fluid in Vertical Holes
Authors: Zhang Qun , Miska Stefan , Kuru Ergun , Azar J. J. 
Published: December 2007

Abstract
A new mathematical model has been developed to investigate the effect of incompressible drilling fluid hydraulics on the buckling behavior and lateral vibration of non-rotating drill pipe in a vertical hole. Dimensional analysis has been incorporated to generalize the solution. The method of Fourier series is utilized to obtain the desired solution.
Several numerical examples are provided to determine the critical flow rate that results in buckling under various conditions of pipe under tension, compression, or compression in the lower portion and tension in the upper. For each of the above cases the following scenarios have been studied: (1) fluid flowing downward in drillpipe; (2) fluid flowing upward in annular space; and (3) fluid flowing downward in drillpipe and upward in annular space simultaneously. The influence of fluid density is also investigated.
Modeling Dependencies Between Geologic Risks in Multiple Targets
Authors: Delfiner Pierre 
Published: December 2007

Abstract
A single-target prospect can be characterized probabilistically by two elements, the risk or probability of success, and the distribution of reserves given success. But there is no obvious way of combining the results of multiple targets into a single representative assessment.
This paper presents a simple approach for aggregating multiple targets for the purpose of prospect ranking. Reserves given success are assumed independent and the novelty lies in the modeling of dependencies between geologic risk factors. Although interdependence can be represented by conditional probabilities, the selection of these values is a problem for most explorationists. In this paper a more practical method is proposed. A matrix is completed for multiple targets specifying which geologic factors are common and which are independent. An outcome tree with dependent targets is created and the probability distribution of aggregate reserves is determined either analytically or by Monte Carlo simulation.
A case study with six targets illustrates the method. Dependencies reduce the probability of at least one success from 92% to 65% and the number of possible outcomes from 64 to 25. This allows a useful grouping by development cases. The method can be used for stacked reservoirs or portfolio analysis.
Alternative Approaches to Modeling Risks in Prospects with Dependent Layers
Authors: Stabell Charles B. 
Published: December 2007

Abstract
A main challenge for wildcat risk and resource assessment of prospects with complex, multiple layers and compartments is handling explicitly and consistently both risk and volume dependencies. This paper compares and contrasts three main alternative approaches to modeling risk dependencies: A complete enumeration of outcome probabilities, a bottom-up approach that aggregates risks using explicit shared risk estimates, and a top-down approach that generalizes the 2-level marginal play, conditional prospect risk model to a 3-level model with a conditional segment level risk. We consider assumptions, data needs and ease of use of the different approaches using illustrative cases and applications.
Horizon Attributes and Fracture-Swarm Sweet Spots in Low-Permeability Gas Reservoirs
Authors: Hart B. S. , Pearson R. A. , Herrin J. M. , Engler T. , Robinson R. L. 
Published: December 2007

Abstract
Horizon attributes, i.e., attributes that numerically describe geometric characteristics of interpreted horizons from conventional (i.e., p-wave) 3-D seismic volumes, hold considerable potential for identifying fracture-swarm sweet spots in low permeability reservoirs. Typically, these attributes (e.g., dip, azimuth, and curvature) are used to define subtle faults that are near the limit of seismic detectability. These subtle structures can play important roles in compartmentalizing conventional reservoirs. However, in low permeability gas reservoirs where fracture permeability is critical, these same attributes can be used to define high-permeability fracture swarms. We illustrate this point with three case studies, two clastic the other carbonate, from the San Juan Basin area of northwestern New Mexico. The Paradox Formation is a Pennsylvanian age low permeability carbonate reservoir. At Ute Dome Field, production characteristics indicate that fractures are the main control on gas production from these carbonates. Comparison of horizon attributes from this level with production data shows that these attributes are defining high-permeability fracture swarms associated with faults. The Mesaverde Group consists of Cretaceous age clastics and is a tight reservoir in the Blanco Field. Again, horizon attributes (including curvature attributes) can be used to define fault-related fracture swarms that will produce at higher rates than surrounding areas. The Dakota Sandstone is another Cretaceous tight gas sandstone. A map of horizon dip in one area shows a trend that is associated with anomalous production from two wells. However, these two wells cannot be described as "sweet spot" wells because their production is not anomalously high. These observations indicate that development drilling plans for low permeability reservoirs should take into account geologic heterogeneity that can be associated with fracture swarms. Undrilled fracture swarms should be targeted to produce high-rate wells. On the other hand, offset wells should specifically avoid drilling into previously tapped fracture swarms to avoid drainage interference. Other factors that need to be considered are: a) the orientation of the fractures with respect to in-situ stress directions, and b) lithologic (i.e., stratigraphic) control on fracture density.
A New NMR Method of Fluid Characterization in Reservoir Rocks: Experimental Confirmation and Simulation Results
Authors: Freedman R. , Sezginer A. , Flaum M. , Matteson A. , Lo S. , Hirasaki G. J. 
Published: December 2007

Abstract
A new magnetic resonance fluid (MRF) characterization method for fluids in porous rocks has been developed. The method uses suites of spin-echo measurements that can be acquired in the laboratory or by a nuclear magnetic resonance (NMR) logging tool. In general, the data suites consist of spinecho measurements with different echo spacings, polarization times, applied magnetic field gradients, and numbers of echoes. These measurements are sensitive to the viscosities and molecular diffusion coefficients of the fluids and therefore provide the information needed for fluid characterization.
The MRF method is based on the inversion of a general multifluid relaxational model that describes the decay of the transverse magnetization in porous rocks containing reservoir fluids. In its most general form, the relaxational model consists of separate contributions to the measured spin-echo signals from all of the fluids that can be present in reservoir rocks; i.e., brine, oil, gas, and oil-base mud filtrate (OBMF), including mixtures of gas dissolved in oil or OBMF. A key ingredient in the multifluid relaxational model is a new phenomenological microscopic constituent viscosity model (CVM) for hydrocarbon mixtures that links diffusion-free relaxation and molecular diffusion in crude oils. The CVM significantly improves the robustness of the inversion so that accurate fluid characterization is possible even when the brine and crude oil T1 and T2 distributions overlap one another. We present experimental results on live and dead hydrocarbon mixtures and crude oils that confirm the validity of the CVM.
The results of a Monte Carlo simulation for a model carbonate formation containing brine, crude oil, gas, and OBMF demonstrate the robustness and accuracy of the inversion. Monte Carlo simulations conducted for different types of rocks containing different amounts and types of fluids demonstrate that the inversion provides quantitative estimates of total porosity, fluid saturations, fluid volumes, bulk volume irreducible water, crude oil viscosity, hydrocarbon-corrected permeability, crude oil T1 and T2 relaxation time distributions, crude oil diffusion coefficient distributions, brine T2 distributions, and apparent brine T1/T2 ratios.
The MRF method was also tested in the laboratory on partially saturated Berea 100 and Indiana limestone rocks containing brine and oil. The water saturations estimated from the NMR data by inversion of the multifluid relaxational model are shown to agree well with the water saturations that were independently estimated from differential weight measurements. The oil viscosity estimates are also shown to be in good agreement with the known viscosity of the oil.