bluuebunny/crossref_metadata_2025_split huggingface dataset:
History Matching of Naturally Fractured Reservoirs Using Elastic Stress Simulation and Probability Perturbation Method
Authors: Suzuki S. , Daly C. , Caers J. , Mueller D. 
Published: December 2007

Abstract
The application of elastic stress simulation for fracture modeling provides a more realistic description of fracture distribution than conventional statistical and geostatistical techniques, allowing the integration of geomechanical data and models into reservoir characterization. The geomechanical prediction of the fracture distribution accounts for the propagation of fracture caused by stress perturbation associated with faults. However, the challenge lies in estimating the past remote stress conditions which induced structural deformation and fracturing, the limited applicability of the elasticity assumption, and the latent uncertainty in the structural geometry of faults. The integration of historical production data and welltest permeability into geomechanical fracture modeling is a practical way to reduce such uncertainty. We propose to combine geostatistical algorithms for history matching with geomechanical elastic simulation model for developing an integrated yet efficient fracture modeling tool.
This paper presents an integrated approach to history matching of naturally fractured reservoirs which includes 1) fracture trend prediction through elastic stress simulation, 2) geostatistical population of fracture density based on fracture trend map, 3) fracture permeability modeling integrating fracture density, matrix permeability and welltest permeability, and 4) numerical flow simulation and history matching. All of these implementations are incorporated into a single forward modeling process and iterated in the automatic history matching scheme. To obtain a history match on a reservoir model, we jointly perturb the large-scale fracture trend and local-scale geostatistical fluctuations of fracture densities rather than perturbing permeability calibrated from fractures. This strategy enables us to preserve the geological/geomechanical consistency throughout the history matching process. The geomechanically simulated fracture trend model is calibrated to both production data and geological structure map (faults and horizons) by finding the optimum remote stress condition for elastic stress-field simulation. The latter is achieved by matching the actually observed structural deformation trend with the simulated one. The smaller-scale fluctuation of fracture density is simultaneously history matched through the probability perturbation method of Caers (2003)1,2. The result of synthetic reservoir application is presented.
Worldwide First Run in Hole of a Dope-Free 13Cr Production Tubing String
Authors: Rignol J. , Parde A. , Thoreau E. , Verdillon L. 
Published: December 2007

Abstract
Thread compounds are used on a common basis throughout the full life of Oil & Gas Tubular Goods (OCTG), whether as a storage compound applied in the mill, or in the yard, or as a make-up compound for running in hole.
Dischargeable compounds have an impact on the environment, due to some of their components such as lead and due to the quantity released. Past initiatives - like green dopes - have brought valuable, but only partial resolution to this problem.
The optimum solution is the increasingly popular dopefree connection approach. This paper presents the first worldwide implementation of a complete Cr13 production string applied with a dopefree connection: 16000 ft of 4" 1/2 13%Cr-L80 Premium CLEANWELL© tubing joints run in a North Sea offshore gas well in the Netherlands.
The paper explains the specific requirements for using this new "no application - no discharge" lubricating film. It also examines the present QA-QC procedures (storage, thread inspection, tally, drift etc…) that ensures" no leaks" in the production string as well as the lessons learnt throughout the entire implementation of this dopefree system.
Finally, in addition to the improvements of existing HSE practices, the paper highlights the other benefits recorded during this first implementation, including rig time savings, improvement of the protection of the threads, reduction of pipe handling.
Integration of Microseismic Fracture Mapping, Fracture and Production Analysis With Well Interference Data To Optimize Fracture Treatments in the Overton Field, East Texas
Authors: Mayerhofer M. J. , Bolander J. L. , Williams L. I. , Pavy A. , Wolhart S. L. 
Published: December 2007

Proposal
This paper discusses the integration of microseismic fracture mapping with fracture engineering, well production results and offset well interference data in the Overton Field, East Texas. Target formation is the Taylor Cotton Valley at depths of about 11,500 ft. The fracturing program in this field included different types of waterfrac and linear gel hybrid frac treatments, which were compared to evaluate the optimal type of fracture design in this area. Detailed production analyses were performed to evaluate well performance in conjunction with fracture geometry measurements provided by microseismic fracture mapping results, calibrated fracture modeling and direct production interference data, which provided interesting insights into effective fracture lengths, reservoir quality, and drainage areas.
Microseismic fracture mapping1,2,4,6,7,14-17 indicated that created fractures are very long. There is compelling evidence that effective hydraulic fracture lengths are also very long, as immediate well interference can be detected in wells that are located along the fracture orientation with very large interwell distances. This means that there is a conductive hydraulic fracture path in place over large distances, with fractures overlapping and linking up wells. One well in this study area was temporarily killed by a fracture treatment in an offset well but production was restored within one day. There was no evidence for a wide fracture network (as has been reported in the Barnett shale), but there may be a small-scale fracture network within a narrow area around the hydraulic fracture.
Production modeling indicates that the permeability feeding the long hydraulic fractures (perpendicular to frac) is on average very low as indicated by production modeling. The low permeability and long fractures will create slim "cigarlike" drainage areas that should be taken into consideration for well placement and spacing strategies.
The results of this work illustrate the application of microseismic mapping to calibrate fracture models3,8,9,10,13 and, with the subsequent integration of production and interference data, to improve well placement and field development strategies. The paper also provides recommendations for optimizing future fracture treatment designs and explores different treament types (waterfracs, and linear gel hybrid fracs) and the effect of increasing job sizes.
Development of Equations and Procedure for Perforation Inflow Test Analysis (PITA)
Authors: Rahman N. M. A. , Pooladi-Darvish M. , Mattar L. 
Published: December 2007

Abstract
Recently short emission tests have been getting attention due to economics, environmental issues or time constraints. Thus, well-testing is sometimes reduced to perforating the well and analyzing the inflow characteristics. The objective of a Perforation Inflow Test Analysis (PITA) is to estimate the initial reservoir pressure, permeability and skin, immediately after perforating the well. This information can be used for evaluating future development strategy. During the entire test period, the surface valve is kept closed, and the formation fluid enters the closed chamber (casing or tubing space) as initiated by a lower cushion pressure than the initial reservoir pressure. However, special analytical procedures are required for analyzing the data, captured through surface or subsurface monitoring, because these perforation inflow tests are shorter than conventional well tests.
In this study, the working equations for analyzing these short tests are developed and presented for both gas and liquid (oil or water) wells, and the procedure required for calculating meaningful estimates of the reservoir parameters will be highlighted. The equations are based on some approximations of the slug-test solution in Laplace space. The radius of investigation during the perforation tests will be estimated, and it will be shown that in presence of measurement errors, radius of investigation will grow to a maximum value. Running the tests for anytime longer will detect just the noise.
A special derivative, called the impulse derivative, will be used to determine if the data collected is sufficient to yield meaningful results from a PITA. It is particularly important that the wellbore flow has diminished to a low level and the reservoir-dominated flow has fully established, if the estimates of initial reservoir pressure, permeability and skin are to be acceptable.
Asphaltene-Induced Formation Damage: Effect of Asphaltene Particle Size and Core Permeability
Authors: Sim S. S. K. , Takabayashi K. , Okatsu K. , Fisher D. 
Published: December 2007

ABSTRACT
The precipitation of asphaltene during CO2 miscible flooding can lead to production losses and reduced efficiencies. Having a clear understanding of the asphaltene deposition mechanism can help the oil industry to develop effective engineering practice to minimize asphaltene deposition and develop treatment program to restore well productivity. This paper presents results of phase behavior and core flood tests conducted at reservoir pressure and temperature conditions to identify the dominating factors associated with permeability reduction during CO2 miscible flood of a light oil reservoir.
Initially, dynamic phase behavior of crude oil and CO2 mixtures were investigated to determine the threshold concentration of CO2 for onset of asphaltene precipitation. The relationship between CO2 concentration and the mass of deposited asphaltene particles were quantified by analyzing the images of the mixtures as well as by physical separation of the deposited asphaltene solids. Laboratory coreflood tests were conducted to investigate the effect of asphaltene deposition in reduction of core permeability. Variables investigated included, initial core permeability, CO2 concentration and quantity and size of asphaltene particles in the oil/CO2 mixtures. Porous media used included sandpack, reservoir carbonate cores and commercial Indiana limestones. The tests were conducted at 100 °C and 3000 psig with reservoir crude oil containing CO2 concentration in the range of 40-70 mol%.
Phase behaviour results indicated that the mass and size of asphaltene particles precipitated from the mixtures were strongly dependent on the CO2 concentration. Coreflood test results showed that the severity of formation damage was related to the initial core permeability as well as the quantity and size of the asphaltene particles precipitated. The damage mechanism was found analogous to the 1/3 and 1/7 rule of thumb that related the size of particulates in injected water to potential permeability reduction. It was also observed that formation damage caused by shallow solid invasion was more readily removed by crude oil injection while remediation of formation damage caused by deep solid invasion, was more difficult.
Integrated Sand and Erosion Alarming on Na Kika, Deepwater Gulf of Mexico
Authors: Stein M. H. , Chitale A. A. , Asher G. , Vaziri H. , Sun Y. , Colbert J. R. , Gonzalez F. A. 
Published: December 2007

Abstract
A pilot test of an integrated sand and erosion alarming process has been implemented in the NaKika field, in the Gulf of Mexico. All wells have sand control completions. Except for one well with a gravel pack completion problem, all the other wells are controlled by a flux limit (SPE Paper 84495).
A Microsoft Excel based program was developed to automatically receive daily morning report data, and perform nodal analysis calculations on all of the wells, in order to estimate: mechanical skin corrected for relative permeability changes, pressure drawdown, gravel pack flux, and wellhead velocities. The wellhead velocities were utilized to calculate erosion rate to estimate metal loss. Corrosion rate at the wellhead was also estimated. All calculated results are sent to OSI PI as data tags and viewable through a commercial real time trend-analysis program. The Excel program results are also automatically emailed to the engineers.
The gravel pack flux limits are used to make sure we do not produce the wells at rates which increase the probability of sand control failure. Monitoring of the flux results were subsequently used to increase the gas rate of one well by 15 MMSCF/D, and an oil well by 4.8 MBOE/D.
Wells were ramped up in a controlled manner via programmable logic controllers. Acoustic sand detectors showed very little sand production, primarily during ramp up. The controlled ramp up is believed to be the most important reason that we have not observed any sustained sand production. After a year of operation, we have had only one minor separator cleanup for sand, most of which has been proppant from double and triple frac packs.
Well Deliverability Predictions for a Low-Permeability Gas/Condensate Reservoir
Authors: Ayyalasomayajula P. , Silpngarmlers N. , Kamath J. 
Published: December 2007

Abstract
It is well known that the deliverability of gas condensate wells can be impaired by the formation of a condensate bank once the bottomhole pressure drops below the dew-point. There have been many excellent laboratory studies on gascondensate relative permeability that describe this phenomenon, but integrated laboratory-simulation-field studies that compare systematic predictions to field performance are few. This work presents a careful and comprehensive evaluation of deliverability of several wells in a low permeability gas condensate reservoir. This sandstone reservoir has permeability ~ 10 md, porosity ~ 10%, and condensate yield ~ 50 bbls/MMscf.
Our approach consists of the following steps - (i) careful selection of core samples that cover the range of expected responses; (ii) design of fluid systems that mimic reservoir fluids, but at lower temperatures; (iii) appropriate relative permeability measurements krg = f(krg/kro, Nc) for a range of flow conditions; (iv) fitting this data to several different relative permeability models for use in reservoir simulators; (v) use of analytical spreadsheet tools to calculate deliverability; (vi) detailed single well compositional models with realistic geology and boundary conditions extracted from full field models, honoring complex producing rules and differential depletion; (vii) comparison of prediction to four wells, three vertical and one inclined.
We have been able to reasonably predict the performance of these wells. The productivity reduction of the wells were found to be in the range of 80%, the majority of which occurred in the initial phases of production. Our ability to reasonably predict the performance has given us confidence that our approach, including measuring only the relevant portion of the relative permeability curves and using synthetic fluids, may be sufficient.
Assessing Producibility of a Region's Gas/Condensate Reservoirs
Authors: Kabir C. S. , Badru O. , Eme V. , Carr B. S. 
Published: December 2007

Abstract
Gas-condensate reservoirs present unique challenges in terms of assessing liquid content and meeting long-term gas deliverability contracts. When production is initiated, liquid accumulation inevitably reduces a well's productivity index, leading to questions about its ability to sustain the demand rate. Questions also arise whether the liquid content is rich enough to justify cycling lean gas to enhance liquid recovery.
This study attempts to address these questions by analyzing data from a large number of West African fields. We used design of experiments (DoE) to derive useful phenomenological correlations for optimal producibility of wells and to discern when a detailed gas-cycling study is warranted. Finite-difference flow simulations in full-compositional mode formed the basis of DoE studies.
We observed that sustained well productivity can be had so long one designs completion intervals commensurate with permeability-thickness product and liquid content. In other words, lower offtake rates should be imposed in unfavorable systems to sustain long-term productivity. When lean gas is cycled, incremental recovery over that of depletion case was observed for fluids with 45 to 178 STB/MMscf condensate yields. The producer-injector distance turns out to be the most dominant variable for condensate recovery. A simple correlation is developed to assess the incremental liquid reserves for screening purposes.
Geologically Consistent History Matching of a Deepwater Turbidite Reservoir
Authors: Hoffman B. T. , Wen X. -H. , Strebelle S. , Caers J. 
Published: December 2007

Abstract
This paper presents an innovative methodology to integrate prior geologic information, well log data, seismic data and production data into a consistent 3D reservoir model. Furthermore, the method is applied to a real channel reservoir from the African coast. The methodology relies on the probability perturbation method. Perturbing probabilities rather than actual petrophysical properties guarantees that the conceptual geologic model is maintained and that any history matching related artifacts are avoided. Creating reservoir models that match all types of data are likely to have more prediction power than methods where some data are not honored. The first part of the paper reviews the details of the probability perturbation method (PPM), and the next part of this paper describes the additional work that is required to history match real reservoirs using this method. Then, a geological description of the reservoir case study is provided, and the procedure to build 3D reservoir models that are only conditioned to the static data is covered. Due to the character of the field, the channels are modeled with a multiple-point geostatistical method. The channel locations are perturbed in a manner such that the oil, water, and gas rates from the reservoir more accurately match the rates observed in the field. Two different geologic scenarios are used, and multiple history matched models are generated for each scenario. The reservoir has been producing for about five years, but the models are matched only to first three years of production. Afterwards, to check predictive power, the matched models are run for the last one and a half years, and the results compare favorably with the field data.
Results of U.S. Department of Energy Deep Gas Well Stimulation Study
Authors: Mayerhofer M. J. , Wolhart S. L. , Rogers J. D. 
Published: December 2007

Abstract
The paper reports on a U.S. Department of Energy sponsored project to evaluate deep gas well stimulation (Deep Trek Program). Under the Deep Trek Program, this study was conducted to evaluate the stimulation of deep wells onshore U.S. and Gulf of Mexico Shelf. The objective of the project was to assess U.S. deep well drilling & stimulation activity, review rock mechanics & fracture growth in deep, high pressure/temperature wells and evaluate stimulation technology in several key deep plays. This paper documents the location and level of deep gas development in the near future, discusses important issues and technology needs, and presents case histories of current stimulation practices for selected fields.
The challenges of drilling and completing deep gas wells are quite significant. Relatively few deep wells (&gt;15,000 feet true vertical depth) are drilled annually. Of the estimated 29,000 wells (oil, gas and dry holes) drilled in U.S. in 2002, approximately 300 were deep wells. Deep drilling peaked at 425 wells in 1998 and fell to 250 wells in 1999 as part of the overall industry downturn. However, successful deep gas wells can be prolific producers and it is projected that natural gas from deep reservoirs will be essential to meeting future domestic supply demand.
The study included a review of deep gas well drilling activity (historical from 1995) and forecast through 2009. Interviews were conducted with operators, service companies and consultants on deep gas well stimulation practices and technology needs by region. Also, key issues with rock mechanics and fracture growth in deep reservoirs were summarized. The following two areas include case studies documented in the paper: South Texas (targeted due to current and future drilling activity); six wells completed in the Lobo sands in Zapata County,Rocky Mountains (targeted due to the huge deep gas resource in place); five wells completed in the Lower and Upper Weber sandstones and Weber Dolomite in the Wamsutter area of Wyoming.
Two-Phase Correlation for Multilateral Well Deliverability
Authors: Kamkom R. , Zhu D. 
Published: December 2007

Abstract
To predict well performance for multilateral wells, an inflow performance relationship (IPR) model is needed to calculate the flow rate and pressure distribution in the horizontal laterals. Several analytical models have been developed over the last 20 years to generate inflow performance relationships (IPR) for single-phase horizontal wells. Similar to vertical wells, analytical solutions for two-phase flow horizontal wells are unavailable because of the complexity of relative permeability and the variable phase distribution in the reservoir. Correlations, leading by Vogel's equation, have been used for two-phase IPR calculations for vertical wells, and the method can be adopted for multilateral/horizontal well applications.
This paper presents a two-phase multilateral well model using a modified Vogel's equation to generate IPR curves for two-phase horizontal laterals and deliverability curves for multilateral wells. The modified two-phase inflow model uses Babu and Odeh's model[3] to calculate the absolute open flow potential, qo, max, for a horizontal lateral, and then use the original Vogel's correlation to generate the relationship between flow rate and pressure. The reservoir anisotropy is considered in Babu and Odeh's model for horizontal well flow, and the wellbore pressure drop was considered interactively with the inflow performance along the wellbore. The overall performance then is presented as wellhead pressure versus total flow rate, flow rate from each lateral, and flow rate distribution along each lateral.
The results of the deliverability model with the modified Vogel's correlation are compared with the results by a single phase analytical model for multilateral wells. Since the overall flow condition and the performance of a multilateral well is very sensitive to the pressure distribution in the well system, a two-phase inflow model provides a better estimate of the pressure and flow rate distribution, and therefore identifies production problems such as cross flow more accurately. The multilateral well model is used to study the effects of fluid properties on flow rate redistribution in the laterals for two phase flow wells, and on overall well performance.