bluuebunny/crossref_metadata_2025_split huggingface dataset:
The Stratigraphie Method: A Structured Approach to History-Matching Complex Simulation Models
Authors: Williams M. A. , Keating J. F. , Barghouty M. F. 
Published: December 2007

Summary
This paper offers a structured approach to performing a history match on a complex, multilayered reservoir model. We recommend tools for interpreting the data and simulation results, and discuss procedures for improving the quality and efficiency of the history-matching process. This approach, the stratigraphic method (SM), was developed over 10 years on various reservoir studies. It has been used successfully on highly complex reservoirs, some containing more than 1,700 wells and over 50 years of production history. We also report on which reservoir parameters most affect matching observed-reservoir performance. This may be helpful to those with less experience working on a history-match project.
Permeability Determination Using Neural Networks in the Ravva Field, Offshore India
Authors: Wong P. M. , Henderson D. J. , Brooks L. J. 
Published: December 2007

Summary
This paper describes the use of the backpropagation neural network (BPNN) technique to predict reservoir permeability using conventional well log data. The technique is demonstrated with an application to the Ravva oil and gas field, offshore India. The Ravva field reservoirs are middle Miocene age nearshore marine sandstones that are often laminated to thinly interbedded shale. The use of conventional permeability-porosity crossplots to predict permeability in this field was not successful. The BPNN permeability prediction model ("RAVVANET") was developed from a data set consisting of core permeability and well log data from two early development wells. The model was blind tested with data from a third well, which was withheld from the modeling process. The results of this study show that BPNN model permeability predictions are consistent with core analysis results.
Acid-Fracturing Treatment: A Surface-Topography Analysis of Acid-Etched Fractures To Determine Residual Conductivity
Authors: Ruffet C. S. , Féry J-J. , Onaisi Atef 
Published: December 2007

Summary
A fracture-acidizing treatment of carbonate formations can be considered successful when a relatively good fracture conductivity remains after treatment. To reach such a goal, an uneven etching of the fracture by acid is expected, so that channels are created that hydraulically maintain the fracture open, once the pressure is released after the job, and thus enhance productivity.
Residual conductivity is the consequence of uneven etching of the surface, but the way this etching occurs in the field is not well understood and, therefore, poorly described. We, thus, propose, in this paper, an experimental methodology to investigate and characterize quantitatively how acid injection conditions affect the fracture surfaces, how the created rough surface is able to support the stress, and, finally, how fracture conductivity can be estimated from the surface topography.
The statistical investigation of surface topography associated with acidizing experiments proposed in this paper, provides a new and interesting method for designing an acid fracturing job. It can be used as an aid to select the best fluid formulation and flow rate for a given formation type and well conditions and to forecast the behavior of the fracture after the treatment.
Prediction of Interfacial Tensions of Reservoir Crude Oil and Gas Condensate Systems
Authors: Zuo You-Xiang , Stenby E. H. 
Published: December 2007

Summary
In this work, the linear gradient theory (LGT) model, the simplified linear gradient theory (SLGT) model, the corresponding-states (CS) correlation, and the parachor method developed by the authors1–4 were extended to calculate interfacial tensions (IFT's) of crude oil and gas condensate systems. Correlations of the model parameters were presented for pseudocomponents. The characterization procedures of Pedersen et al.5 and the SRK equation of state (EOS)6 were used to calculate vapor-liquid equilibria (VLE). To the exclusion of the near-critical region, the IFT's calculated by all the models except the CS correlation were in good agreement with the measured IFT data for several crude oil and CO2/oil systems. The SLGT model and the parachor model perform better than the LGT model and the CS correlation. For N2 volatile oil systems, the performance of the LGT model is better than that of the SLGT model and the parachor model. For gas condensate systems, the predictions by use of the SLGT model are in good agreement with the measured IFT data. In the near-critical region, a correlation was proposed for estimations of IFT's for CO2/oil systems, and satisfactory correlated results were obtained.
Permanent Gauge Pressure and Rate Measurements for Reservoir Description and Well Monitoring: Field Cases
Authors: Unneland Trond , Manin Yves , Kuchuk Fikri 
Published: December 2007

Summary
This paper presents a procedure for interpreting data acquired with permanent downhole pressure sensors in association with surface or downhole rate measurements. The usefulness of this data source in reservoir description and well performance monitoring is illustrated.
Unlike previously published examples, this interpretation is based on the analysis of a stream of data acquired over a long period of time, thus taking advantage of the continuous nature of the measurements. Three field cases are presented using the pressure and rate data in decline-curve analysis for wells with a variable downhole flowing pressure.
Because such an interpretation is conducted while production continues, the interpretation is particularly well suited for a well or group of wells under extended testing that are equipped with downhole gauges and are flowing through surface separation and metering systems. Wells completed with both permanent downhole rate and pressure measurements are also ideal candidates for this analysis.
Finally, the influence of the pressure sensor long-term drift and the rate measurement error on the interpretation results and future forecasts are investigated.
Productivities of Fractured and Nonfractured Deviated Wells in Commingled Layered Reservoirs
Authors: Larsen Leif 
Published: December 2007

Summary
Direct analytical methods are introduced to determine productivity indices of fractured and nonfractured deviated wells in commingled layered reservoirs, including cases with horizontal wells. For non-fractured wells, the total productivity index (PI) can be obtained by adding the individual layer PI's. A similar straightforward addition scheme can also be used for many fractured wells, but a more direct approach covering all well and fracture elements might be needed if at least one of the fractures penetrates more than one additional layer above or below the wellbore layer.
Steady-State and Transient Thermal Performance of Subsea Hardware
Authors: Zabaras G. J. , Zhang Jianfeng 
Published: December 2007

Summary
The thermal performance of subsea hardware is of ultimate importance to the economic development and reliable operation of deepwater subsea oil and gas systems because of the potential for hydrate formation. Results of numerical calculations are presented on the thermal performance of subsea equipment such as wellheads, tubing and flowline jumpers, and flowline field joints. In contrast to previous published studies on the thermal performance of insulated subsea wellbores and flowlines, this paper addresses the thermal performance of the subsea equipment that can provide weak thermal links for the subsea system.
Although subsea insulated flowlines can eliminate or reduce the risk of hydrate formation during steady-state production, they may not provide sufficient cooldown time before hydrates are formed during an emergency shutdown. Subsea wellheads, pipe field joints, manifold jumpers, and flowline and tubing jumpers are very difficult to insulate effectively. As a result, these pieces of equipment exhibit faster cooldown to hydrate-formation temperature than does either the wellbore or the flowline.
A two-dimensional (2D), general-purpose, finite-element, partial-differential equation solver was used to analyze the steady-state and transient thermal behavior at different cross sections of the subsea tree. In contrast to the intuitive common belief that a subsea-tree cooldown time to hydrate-formation temperature is on the order of several hours, a cooldown time less than 2 hours was determined after a system shutdown. Steady-state analysis of a flowline field joint indicates that the joint degrades the flowline thermal performance, causing up to a 20% increase in the flowline overall heat-transfer coefficient. To our knowledge, such results have not yet been presented in the literature.
This paper presents a new method for predicting pressure profiles in oil and gas wells. The method combines mechanistic flow-pattern transition criteria with physical models for pressure-loss and liquid-holdup calculations for each of the flow patterns considered. Past published methods relied heavily on empirical fit of limited field data. As a result, they are inaccurate when used outside the range of data upon which they are based. In contrast, the new method is universally applicable to all types of wells under all operating scenarios because it is based on fundamental physics rather than the curve-fit of field data. Its prediction performance has been demonstrated by extensive comparison to field data from a variety of wells.
EOR Screening Criteria Revisited—Part 2: Applications and Impact of Oil Prices
Authors: Taber J. J. , Martin F. D. , Seright R. S. 
Published: December 2007

Summary
Screening criteria are useful for cursory examination of many candidate reservoirs before expensive reservoir descriptions and economic evaluations are done. We have used our CO2 screening criteria to estimate the total quantity of CO2 that might be needed for the oil reservoirs of the world. If only depth and oil gravity are considered, it appears that about 80% of the world's reservoirs could qualify for some type of CO2 injection.
Because the decisions on future EOR projects are based more on economics than on screening criteria, future oil prices are important. Therefore, we examined the impact of oil prices on EOR activities by comparing the actual EOR oil production to that predicted by earlier Natl. Petroleum Council (NPC) reports. Although the lower prices since 1986 have reduced the number of EOR projects, the actual incremental production has been very close to that predicted for U.S. $20/bbl in the 1984 NPC report. Incremental oil production from CO2 flooding continues to increase, and now actually exceeds the predictions made for U.S. $20 oil in the NPC report, even though oil prices have been at approximately that level for some time.
Practical Procedure To Predict Cresting Behavior of Horizontal Wells
Authors: de Souza A. L. S. , Arbabi Sepehr , Aziz Khalid 
Published: December 2007

Summary
Water and gas cresting in horizontal wells are important phenomena in reservoirs that have an aquifer or a gas cap. In practical situations, many reservoirs are produced under supercritical rates, and a breakthrough of the displacing phase becomes inevitable. At the beginning of a reservoir simulation study, it is desirable to make an estimate of the breakthrough time and the post-breakthrough behavior. Grid sensitivity runs are also required to obtain the appropriate gridblock sizes. An accurate representation of cresting behavior requires a very fine grid, which is not always practical. In this work, a procedure was developed to obtain accurate breakthrough times by use of just coarse grid simulations. The flow equations were written in dimensionless form, and important parameters affecting multiphase flow were identified. Simple correlations for a quick estimate of breakthrough time, maximum oil rate, and post-breakthrough behavior were derived on the basis of an appropriate set of dimensionless variables and an extensive number of simulation runs. The effects of gridblock size and grid pattern were investigated in detail. Effects of rate, mobility ratio, well drainage area, well height, and endpoints and shapes of relative permeability curves were also included. A procedure to derive pseudofunctions, either by numerical correlations or coarse grid simulations, is also presented. These pseudofunctions can be used to improve the performance of coarse grid simulations. An optimum grid pattern to start a reservoir simulation study is proposed. An application with real data shows that the correlations and procedures derived are reliable and accurate and can be used for quick estimates before starting a reservoir simulation study.
A Case Study in Scaleup for Multicontact Miscible Hydrocarbon Gas Injection
Authors: Jerauld G. R. 
Published: December 2007

SummaryWe describe the strategy and results of scaleup done to simulate a multicontact miscible hydrocarbon water alternating gas (WAG) injection process. To adequately model both oil recovery and solvent retention in WAG, one must model three-phase flow including gas trapping. Scaleup of the multicontact miscible gas process is particularly difficult because of the very fine-scale structure of the gas fingers and the miscible front. The case studied is a heterogeneous mixed wet reservoir with a transition zone down to an underlying aquifer. The objective was to develop pseudo relative permeability curves and other parameters that are suitable for running in a full-field limited compositional model with three hydrocarbon components.Both history-matching and systematic approaches were used to generate pseudo relative permeability curves that reproduced results of high-resolution, fully compositional (FC) reference simulations. Dynamic pseudoization techniques were used to derive first guesses at pseudos, but required further calibration to reproduce reference simulations successfully. In matching incremental miscible gas/oil recovery timing and solvent retention, varying three-phase water relative permeability was much more effective than varying the mixing parameter.The predictive capability of pseudos was tested for changes with respect to slug size, WAG ratio, and solvent enrichment. Pseudos derived for one pattern or cross section were tested in other patterns or cross sections. Pseudos worked well with respect to changes in WAG ratio, fairly well with respect to changes in solvent enrichment, and moderately well for changes in slug size. They were less robust with respect to changes in description.
Analysis of Hydraulic Fracture Closure in Laboratory Experiments
Authors: Dam D. B. van , Pater C. J. de , Romijn Remco 
Published: December 2007

Summary
Conventional models of hydraulic fracture closure make assumptions about the fracture geometry and rock mechanical behavior. In this paper we present the results of scaled laboratory experiments. We show that deviations from conventional assumptions influence leak-off volumes, mechanical behavior, and pressure decline significantly. We discuss mechanisms that lead to these deviations from assumptions during fracture closure.
Integrating Pressure Data From Formation Tester Tools and DSTs To Characterize Deepwater Fields, East Kalimantan, Indonesia
Authors: MacArthur Jack , Vo D. T. , Palar Steve , Terry Albert , Brown Trevor , Hariyadi Hariyadi , May Ron 
Published: December 2007

Summary
In the past 3 years, two significant commercial hydrocarbon accumulations in the deep waters of the Makassar Strait, Indonesia, were discovered. These fields are located approximately 16 miles northeast of the giant Attaka field in 1,400 to 3,400 ft of water.
To date, more than 40 exploration and appraisal wells have been drilled in both fields, and extensive pressure data have been collected by formation tester tools and drillstem tests (DSTs). The pressure data, used with other data such as seismic and well logs, have enabled us to characterize deepwater turbidite sand reservoirs.
In this deepwater environment, DSTs are used selectively and only with strong justification because of their prohibitive cost. Instead, the use of the pressure-testing tool is pushed to its limit to gain extensive data on pressure, rock, and fluid properties conventionally obtained by DSTs.
This paper will show how the deepwater reservoirs were characterized by means of pressure data from formation tester tools and DSTs to complement geological and seismic data interpretations. Reservoir characteristics such as fluid type, fluid contacts, reservoir connectivity, and sand geometry can be inferred from the pressure gradients and pressure transients. These data are used in constructing reservoir fluid-flow models for a field-development plan.
Formation Electrical Anisotropy Derived From Induction-Log Measurements in a Horizontal Well
Authors: Bang Jon , Solstad Arne , Mjaaland Svein 
Published: December 2007

Summary
An existing theory describes how electrical anisotropy in the formation affects the response of resistivity logging tools. We have related this theory to the processing of logging while drilling (LWD) induction logs and are thus able to calculate the anisotropic resistivities directly from the logs.
The method has been demonstrated by application to logs from a horizontal well section. Anisotropy ratios of 2 to 5, and occasionally higher values, were obtained for this formation. We also addressed the accuracy of these numbers by using independent sets of input logs. The results indicate that the logs are influenced by factors like invasion, in addition to the anisotropy.
Our approach provides a fast and efficient computer algorithm. The output is calculated at the depths of the input logs; hence, the resulting anisotropy becomes a depth-dependent formation property.
A Fast and Direct Method of Permeability Measurements on Drill Cuttings
Authors: Egermann P. , Lenormand R. , Longeron D. , Zarcone C. 
Published: December 2007

SummaryPermeability is one of the most important petrophysical parameters for reservoir characterization, but also one of the most difficult to obtain. Logs provide a good estimate of porosity and saturations, but the accuracy on permeability derived from nuclear magnetic resonance (NMR) is rather poor. So far, reliable values of permeabilities are obtained only from laboratory measurements on core samples for local measurements and well testing for a larger scale-averaged determination.We present an original method for measuring the permeability of drill cuttings without any specific laboratory conditioning (cleaning, coating, etc.). A volume of approximately 100 cm3 of cuttings is placed in a pressure vessel. The cell is then filled with a viscous oil. The process of oil invasion into the cuttings always traps a certain amount of gas. When a pulse of pressure is applied on the cell, the oil enters into the cuttings thanks to the gas compressibility. The permeability is then derived from the dynamic of the oil invasion by using a simple model.The method was tested by using various crushed-rock samples of known permeability. Excellent reproducibility and good agreement between cores and cuttings permeabilities were found for many decades of permeabilities. This method presents many advantages. The measurements can be performed in a few minutes, leading to the possibility of operating on site during drilling. The limitations of the method are related mainly to the size, the representativity of the drill cuttings, and the absence of the confining stress.In developing this method, our purpose is not to replace core analysis but, rather, to provide additional quick and inexpensive information on reservoir characterization.
Timestep Selection During Streamline Simulation Through Transverse Flux Correction
Authors: Osako Ichiro , Datta-Gupta Akhil , King Michael J. 
Published: December 2007

SummaryStreamline simulators have received increased attention because of their ability to effectively handle multimillion-cell detailed geologic models and large simulation models. The efficiency of streamline simulation has relied primarily on simulators' ability to take large timesteps with fewer pressure solutions within an IMPES formulation. However, unlike conventional finite-difference simulators, no clear guidelines are currently available for the choice of timestep for pressure and velocity updates. This has remained largely an uncontrolled approximation, either managed by engineering judgment, or by potentially time-consuming timestep size sensitivity studies early in a project. This is clearly related to the lack of understanding of numerical stability and to the lack of error estimates during the solution.We propose a novel approach for timestep selection during streamline simulation based on three elements. First, we reformulate the equations to be solved by a streamline simulator to include all of the 3D flux terms—both aligned with and transverse to the flow directions. These transverse flux terms are totally neglected within the existing streamline simulation formulations. Second, we propose a simple grid-based corrector algorithm to update the saturation to account for the transverse flux. Third, and most importantly, we provide a discrete Courant-Fredrich-Levy (CFL) formulation for the corrector step that leads to a mechanism to ensure numerical stability through the choice of a stable timestep for pressure updates. This discrete CFL formulation now provides us with the same tools for timestep control as are available within conventional reservoir simulators.We demonstrate the validity and utility of our approach using a series of numerical experiments in homogeneous and heterogeneous ¼ five-spot patterns at various mobility ratios. For these numerical experiments, we pay particular attention to favorable mobility ratio displacements, as they are known to be challenging to streamline simulation. Our results clearly demonstrate the role of the transverse flux and our proposed CFL formulation on the accuracy of the solution and on the appropriate choice of timestep across a range of mobility ratios. The proposed approach eliminates much of the subjectivity associated with streamline simulation, and provides a basis for automatic control of pressure timestep within full-field streamline applications.
The Disc Bit - A Tool for Hard-Rock Drilling
Authors: Plácido J. C. R. , Friant J. E. 
Published: December 2007

SummaryThis paper traces the development of a radically different design of drill bit, describing its concept, laboratory work, and the latest field trials.Disc-bit technology is based on the single-rolling disc cutter. This cutter was first used successfully in rock on a tunnel-boring machine in 1956. By the early 1970s, virtually every rock-tunneling machine in the world had evolved from picks, tungsten carbide button cones, or multirow tapered cutters to the single-row disc. By then, practical field experience had demonstrated the superior performance of tunneling machines. Further, the Colorado School of Mines (CSM) began scientific studies and published data comparing the specific energy of excavation of various tools on the basis of full-scale laboratory testing. These studies clearly showed that the single-row disc cutter required less energy than conventional cutters used in roller cones to excavate a given volume of rock. With energy at the cutting face always a limited commodity, a lower energy requirement translated to a higher rate of penetration (ROP).Not until the mid-1990s was the concept of the single-rolling disc cutter applied to drill bits. Very small—3¼-in. Mini-Disc™— cutters were evaluated at CSM and found to be extremely efficient and sufficiently robust to be used on drill bits as small as 7⅞ in. An evaluation of an 8½-in. disc bit was performed at the Gas Research Inst. (GRI) Catoosa Test Facility in Oklahoma. The U.S. GRI sponsored an effort to develop the concept through laboratory and field testing. Other field trials were sponsored by private and government grants, including the most recent test funded by a joint industry project (JIP) and managed by Petrobras.