bluuebunny/crossref_metadata_2025 huggingface dataset:
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

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

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

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

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

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

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 (>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

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.
A Comprehensive Model of Temperature Behavior in a Horizontal Well
Authors: Yoshioka K. , Zhu D. , Hill A. D. , Dawkrajai P. , Lake L. W.
Published: December 2007

Use of distributed temperature sensors is becoming increasingly common for monitoring producing sections of horizontal wells through a real-time measurement of a temperature profile. This information can potentially be inverted to infer the types and amounts of fluid entering along the wellbore. This information is essential for reservoir management to identify excessive water or gas influx, to guide the action of sliding sleeves or other downhole flow control devices, and to decide if reservoir stimulation is needed in a particular horizontal section.

The inferences described above require a model to translate temperature information into flow information. This paper presents a model for predicting the temperature profile in a nominally horizontal well during normal production (steady-state flow). A forward model of the temperature profile caused by given flow conditions can be the basis of the inverse model needed to determine flow profiles

Prediction of the wellbore temperature profile requires models of all of the often-subtle thermal effects occurring in the reservoir and in the wellbore itself. For the reservoir temperature model, we couple mass and energy balances of fluid flow in a permeable media in a box-shaped homogeneous reservoir with a wellbore temperature model using a multisegment technique. Similarly for the wellbore, we couple mass, momentum, and energy balances to model pressure and temperature behavior. The models presented in this paper account for Joule-Thomson effects, and convective and conductive heat transfer. The primary results of the model are estimates of the extent of temperature change from geothermal temperature during flow. Results show that temperature changes of a few degrees are possible; temperature changes of this magnitude are certainly detectable with current technology. A second result is a demonstration of the inference of single phase and multiphase flow profiles from a synthetic case. Sensitivity studies with the model illustrate the flow conditions that cause measurable temperature changes or anomalies that could be recognized in an analysis of distributed temperature measurements.
Laboratory and Field Study of the Influence of Simple Carboxylates on Oilfield Corrosion and Inhibition
Authors: Martin R. L. , Logan P. D.
Published: December 2007

The influence of simple carboxylates on oilfield chemistry measurements, steel corrosion, and corrosion inhibition was studied. In most cases, the error in the field measurement of dissolved CO2 was found to be small. In all but two cases examined, the error in bicarbonate ion measurement was small because of the large actual bicarbonate ion to carboxylate ratio.

The presence of acetate and propionate ions in laboratory tests always accelerated the uninhibited corrosion rate of mild steel because of an increase in cathodic kinetics when the steel was behaving actively. In passive systems, anodic increases were seen.

Both acetate and propionate were detected in field samples; in only one case butyrate was observed. Corrosion inhibitors were effective at controlling corrosion even in the presence of these ions in both laboratory and field conditions.
Waterflood Surveillance and Control: Incorporating Hall Plot and Slope Analysis
Authors: Silin D. B. , Holtzman R. , Patzek T. W. , Brink J. L. , Minner M. L.
Published: December 2007

Waterflood automation at a field scale is a complex coupled problem. In our analysis, data from injecting and producing wells, as well as satellite differential interferograms (InSAR) are used as the inputs. Some information processing is carried out on-line automatically, and other needs personnel expertise. Dynamic adaptive control is performed in the mixed openloop-feedback mode. Our surveillance-control system is being implemented in Sections 32 and 33 of the Lost Hills diatomite field, CA, USA.
Modeling of Laser Spallation Drilling of Rocks for Gas– and Oil Well Drilling
Authors: Xu Z. , Yamashita Y. , Reed C. B.
Published: December 2007

High power lasers can weaken, spall, melt and vaporize natural earth materials with thermal spallation being the most energy efficient rock removal mechanism.The most interesting focus of recent laser rock drilling research is on developing a laser rock spallation technique to drill large and deep holes in rocks, a potential application in gas and oil well drilling having a rock removal rate higher than that of conventional rotary drilling as well as that of flame-jet spallation.Research is also focused on using laser rock spallation to make perforation channels with improved permeability of the perforated rocks.However, laser rock spallation is a very complex phenomenon that depends on many factors.Fundamental understanding of this complex phenomenon is crucial to the success of its application to the petroleum industry.

In this paper, we propose a combined approach to this complex problem, that is establishing models for each of the physical phenomena based on the finite difference method (FDM), then combining them into one numerical procedure using the Combined Unified Procedure (C-CUP) method.With this approach, the transient temperature and stress distributions in dry or water-saturated rocks exposed to a laser beam have been calculated.The spallation boundary and rock removal efficiency have been determined for different laser conditions.The modeling results provide a better understanding of laser rock spallation phenomenon and most importantly, guidelines for selecting processing parameters for fast rock removal.
Unified Modeling of Gas/Oil/Water Pipe Flow—Basic Approaches and Preliminary Validation
Authors: Zhang H. -Q. , Sarica C.
Published: December 2007

A unified model is proposed for the prediction of flow behavior during production and transportation of gas, oil and water through wellbores and pipelines.In gas-oil-water three-phase pipe flow, the phase distributions and hydrodynamics are described based on two criteria: gas-liquid flow pattern and oil-water mixing status.The three-phase flow is treated as gas-liquid two-phase flow if the two liquids are fully mixed or as a three-layer stratified flow at low flow rates in horizontal or slightly inclined pipes.Most three-phase flows fall between these two extremes: partially mixed with slippage between the two liquid phases.Closure relationships describing the distribution between the liquid phases, namely mixing and inversion are proposed.The model predictions are compared with experimental data of gas-oil-water pipe flows. Significant improvements are observed over the predictions by the two-phase unified model of Zhang et al.[1] which assumes fully mixed liquid phase.
Methodology of Investigating the Compositional Gradient within the Hydrocarbon Column
Authors: Hussein H. H. , Mahgoub I. S.
Published: December 2007

The phenomenon of variation of fluid properties with depth was investigated in many of the Gulf of Suez and Western Desert fields of Egypt. This phenomenon primarily exists in reservoirs with large closures (large thickness or high dip angle, even for thin formations) where the gravitational forces have a significant effect on the overall composition of the system over the geological time.[1,2,3] The phenomenon often exists also in high shrinkage oils, volatile oils4 and rich gas condensates as well as in black oils. Such compositional grading can have significant influences on various aspects of reservoir development. This must be taken into account during estimation of the stock-tank oil initially in place of such fields and well/reservoir behavior evaluation.

This paper presents an engineering evaluation for validating PVT lab analyses of many fluid samples collected at different depths from several reservoirs of different fields. As a result of this evaluation, the valid samples were supportingfluid property variation with depth where its properties can be correlated as a linear function of depth.

Two methods have been used for correlating the fluid properties with depth. The first method relies only on the experimental PVT data provided by the laboratories while the second method uses an equation of state to predict the fluid properties from the experimentally determined compositional analyses. The second method make use from the advantage that in this particular case the equation of state parameters assigned to each hydrocarbon and pseudo-hydrocarbon component within the oil column should be constant for all valid samples. In this method, the most accurate reservoir fluid composition for one of the valid samples was used to predict the reservoir fluid composition and its corresponding PVT properties at different bottomhole locations. The prediction procedure is a combination of stream blending and flash liberation processes to estimate the reservoir fluid properties at shallower and deeper depths from the depth of the selected sample.

Once the fluid properties of the compositional gradient are developed, the engineer can proceed using either black oil or compositional model to match the history and predict the performance of the reservoir under the acting drive mechanism.
Tidal Pressure Response and Surveillance of Water Encroachment
Authors: Langaas K. , Nilsen K. I. , Skjaeveland S. M.
Published: December 2007

A review of the tidal response in petroleum reservoirs is given. It is caused by periodic changes in overburden stress induced by the ocean tide. The "tidal efficiency factor" is derived by two different approaches and is in line with a recent well test in the Ormen Lange gas field.

For small geomechanical pertubations, like the tidal effect, we show that a simplified coupling of geomechanics and fluid flow is possible. The coupling is easy to implement in a standard reservoir simulator by introducing a porosity varying in phase with the tide. Simulations show very good agreement with the theory.

The observation of the tidal response in petroleum reservoirs is an independent information provider, i.e., it provides information in addition to the (average) pressure and its derivative from a well test. The implementation of the tidal effect in a normal reservoir simulator gives us the possibility to study complex multiphase situations and to evaluate the potential of the tidal response as a reservoir surveillance method. The case studies presented here focus on the possibility to observe water in the near-well area of a gas well.
Ultrafine-Scale Validation of Upscaling Techniques
Authors: Wang K. , Sepehrnoori K. , Killough J. E.
Published: December 2007

A combination technique of parallel simulation technology and upscaling algorithms is described. Based on our case studies, the results from the fine-scale model may appropriately be used to guide the upscaling procedure via a tuning procedure. This tuning procedure has been explored in the study to obtain results that are in close agreement with fine-scale simulation results. The combination of parallel simulation technology and upscaling algorithms can be used to provide a better estimation of the amount of uncertainty in predicted oil recovery for real fields. The concept of local global upscaling has been extended to include a technique that honors arbitrary faults in complex geological environments.

Several single-phase upscaling techniques are applied to an analog Gulf of Mexico reservoir model and a synthetic model. For the Gulf of Mexico reservoir model, we obtained results that were in close agreement with coarsened models obtained from the parallel simulations using the fine-scale model. In this case, the CPU time of one simulation run with 20 years of production time was significantly reduced from 22 hours, using a PC cluster with 8 processors computer, to 2 minutes, a single processor, applying upscaling methods. For the synthetic model, the agreement between coarse-scale model and the fine-scale model using the same upscaling method is within engineering accuracy.
Efficient Assessment and Optimization of a Deepwater Asset Development Using Fixed Pattern Approach
Authors: Ozdogan U. , Sahni A. , Yeten B. , Guyaguler B. , Chen W. H.
Published: December 2007

Decisions made during the reservoir development phase have major impact on the project economics. Due to reservoir complexity and severe nonlinear interactions between decision parameters, automated optimization algorithms may be needed to supplement intuitive reservoir engineering analysis. Previous algorithms, proposed for well placement optimization, search for optimum well locations without full consideration of engineering knowledge and practice. This may result in degradation of optimization efficiency (number of simulations) and output unrealistic suboptimal well configurations.

This study proposes an approach that superimposes engineering knowledge and practice on an automated optimization routine (the Hybrid Genetic Algorithm, HGA) to maximize the value and efficiency of field development optimization. The new approach is called the Fixed Pattern Approach (FPA), since it enforces the HGA to locate thewells on a user defined pattern inspiring from the idea that the wells are more likely to be drilled in specific patterns (line, staggered-line, five-spot etc.). The FPA essentially incorporates reservoir engineering concepts within the parameterization of optimization problem and reduces the search-space size considerably by eliminating the simulation of infeasible development scenarios.

The FPA was applied to a deepwater field to get a quick understanding about the possible optimum development scenarios. In the scope of this study, finding the optimum development plan was defined as determining the optimum number and location of producers and injectors, as well as production rates and the starting time of injection that maximizes the Net Present Value (NPV) of the project. These parameters were optimized simultaneously using a black oil reservoir simulator as the objective function evaluator. Comparison with respect to the conventional window approach showed that FPA significantly reduced the CPU time and resulted in practical and economical well locations. Uncertainty in the geological properties (porosity, permeability) and reservoir structure was also addressed for this field by performing optimization on five different models constructed by a Plackett-Burman experimental design. The new methodology recommended an optimum field development plan while taking the uncertainty of property distributions and reservoir structure into account.
Installation and Application of Permanent Downhole Optical Pressure/Temperature Gauges and Distributed Temperature Sensing in Producing Deepwater Wells at Marco Polo
Authors: Weaver M. , Kragas T. , Burman J. , Copeland D. , Phillips B. , Seagraves R.
Published: December 2007

The deepwater environment presents numerous challenges in the production of oil and gas wells. The expense of intervention operations and the corporate bottom line impact of production optimization have generated a need for more sophisticated data gathering and monitoring systems. However, implementing these new technologies in deepwater is challenging because of a lack of installation experience in this environment and difficulty quantifying full cycle benefits.

One recent successful application of new technology is the use of permanently installed downhole optical pressure/temperature gauges and distributed temperature sensors (DTS) to monitor well performance in the producing wells at the Marco Polo field in the deepwater Gulf of Mexico. Innovative techniques were utilized during the facility commissioning and completion operations, allowing these gauges to be installed more efficiently than in the past. The resulting cost savings helped to minimize the additional expenses associated with implementing this technology.

The information from the downhole optical monitoring system has proven useful not just in providing pressure data for reservoir management and drawdown maintenance, but in application of the DTS data in different production scenarios. DTS data has been used to monitor well performance for flow assurance purposes. It has been used with the gas lift system to define valve setting parameters during the job design and to monitor the point(s) of gas injection once the design is in place. To further enhance the value of information from the downhole optical monitoring system, the data is directly available via the internet for real time evaluation.
Platform-Free Fields for Stranded Gas Development: Science or Fiction?
Authors: Rivero M. , Nakagawa E.
Published: December 2007

The requirement for larger and complex production platforms for the development of deepwater gas fields worldwide makes the exploitation of these resources unfeasible. Aiming at reducing the size of these facilities and, consequently, the field development costs, the industry has been conducting, for several years, initiatives in sub-sea processing.

This paper proposes a drastic paradigm shift to meet the requirements of stranded gas: the substitution of surface hydrocarbons processing located in production platforms by down-hole and sub-sea facilities. The vision of Platform Free Fields (PF2) challenges R&D groups to provide real step changes for the feasibility of the gas business. A systematic pathway towards PF2 is analyzed considering economical drivers, an extensive review of the state-of-the-art technology, challenges associated to well architecture and construction, design of down-hole and sub-sea production processes and flow assurance implications.

An analysis of the existing R&D and efforts associated with the exploitation of offshore deepwater gas fields is presented. Based on such analysis and the major challenges involved in the PF2 concept, the paper discusses the viability of such vision and proposes an approach for it. The value creation for each stepwise development is commented along with the modularity and reliability of the concept.

The PF2 constitutes a vision to be shared by all parties involved in the development of stranded gas fields. The vision will guide and encourage industry collaboration towards the goal of making possible the exploitation of such stranded resources far more effectively and likely to succeed than if driven by isolated efforts.

Finally, the paper presents a technical and critical review of tendencies and highlights the most important issues to be addressed for a paradigm change: pushing limits and pulling innovation based on people's experience and knowledge.
Long-Term High-Temperature Laboratory Cement Data Aid in the Selection of Optimized Cements
Authors: Jennings S. S.
Published: December 2007

Cements placed in gas wells for Saudi Arabia drilling operations were evaluated for physical properties. Three intermediate casing cement compositions were tested. The cement systems tested were: 1) bentonite extended, 2) standard density class G and 3) optimized particle packing lightweight system containing hollow ceramic spheres. These tests were requested because of concerns that the cements that were currently being used were not durable in the long term. Khuff and pre-Khuff gas wells in Saudi Arabia have high production rate potential therefore the curing test temperature of 300 oF and test pressures of 3000 psi were applied to the samples. The samples were cured for one year.

The tests performed were API compressive strength tests, permeability, shrinkage or expansion, Young's Modulus, Poisson ratio, rheology and settling. Data for 24 hour, 7 days, 1, 2, 3, 6, 9 and 12 months test periods are presented for all cements.

Certain cements, for which there are no previously published shrinkage data, have been identified.New technology in cement laboratory testing identified undesirable properties in certain cements. Using this new lab technology, some cements exhibited undesirable short and long-term physical properties. Data representing various cement slurry designs and corresponding physical properties results are included in this paper.
Low Cost Multilateral on Gullfaks
Authors: Lie O. H. , Fraser S.
Published: December 2007

Gullfaks is a typical mature field where cost efficient solutions need to be in focus. There is also the challenge that old wells produce at low rates, but nevertheless at rates not drastically lower than those that an alternative use of the slot can deliver. One solution to this challenge is to maintain production from the old well while simultaneously gaining inexpensive access to new a drainage point(s).

B-1A on the Gullfaks field was drilled and completed in January 2003 using hollow whipstock technology. The operation was a technical success which proved that Multilateral (MLT) solutions can be delivered at costs only marginally above those of a conventional sidetrack. To further enhance the value of the slot, a second through tubing MLT lateral was added in January 2005.

The key considerations during the planning phase were proven solutions, cheap technology and low risk. This paper illustrates the decision process prior to choosing this particular technology, the installation process itself, the lessons learned and the strategy which may be applied in the future.
Improved Reservoir Management With Intelligent Multizone WAG Injectors and Downhole Optical Flow Monitoring
Authors: Sandøy B. , Tjomsland T. , Barton D. T. , Daae G. H. , Johansen E. S. , Vold G.
Published: December 2007

A 4-zone intelligent WAG injector was installed at the Statoil Veslefrikk Field in the North Sea, in May 2004. The completion includes one on/off and three variable downhole chokes for controlling injection rate into each of the four zones. The completion also includes three downhole optical flowmeters and three optical pressure and temperature gauges. Measurement of the surface injection rate and the rate from each of the three flow meters provides real-time measurement of injection rate into each zone, regardless of choke positions.

The well is on a Water Alternating Gas (WAG) cycle where one zone is primarily intended for gas injection and the other three zones are primarily intended for water injection. Therefore, equipment that can control and measure water and gas flow with no changes in hardware was critical for the success of this installation.

The combination of downhole chokes and flowmeters allow full control and monitoring of zonal injection rates and has proved to be a valuable tool in managing reservoir pressures and optimizing production. After more than one year of operation during water injection, all the valves and the optical monitoring equipment are functioning satisfactorily. It is estimated that up to about half of the well's value creation during its expected lifetime is due to the DIACS* installation.
How To Estimate the Value of the Information (VOI) of a 4D Seismic Survey in One Offshore Giant Field
Authors: Steagall D. E. , Gomes J. A. T. , Oliveira R. M. , Ribeiro N. M. S. J. , Queiroz R. Q. , Carvalho M. R. J. , Souza C. Z.
Published: December 2007

The decision of acquiring or not, a new reservoir data goes through the difficult estimation of the economic value of this information. This paper presents the methodology used to estimate the value of information of a new seismic survey in the Marlim offshore giant field, located at Campos Basin, Brazil.

The main objective of this new 4D seismic is to enhance the geologic characterization and show the fluid changes in the reservoir that will allow an optimization and a decrease of the risk of the new well projects and the identification of new opportunities.

The estimate of the value of the information is based on the increment of the expected monetary value of the projects with a new 4D seismic data.

The developed methodology has the following steps: Identification of the projects of new locations that would be benefit with the new seismic up to 2010; the analysis of uncertainties;quantification of the risks of the projects; definition in types of expected gains of the new information; estimation of the success probability with and without new seismic; estimation of the net present value of each project with flow simulation; estimation of the expected monetary value of each project with and without new seismic using the decision tree technique; and finally the estimation of the value of seismic information to be acquired.

In this study the flow simulations were done respecting all production facilities, as processing capacities, well heads, slots in platforms and the schedule of initial operation of the wells, allowing more realistic results to support the decision to acquire a new 4D seismic.
NMR Applications For The Determination Of Sedimentary Facies And Porosity Systems In Carbonatic Core Plug Samples
Authors: Alfredo M. N. , José M. B.
Published: December 2007

The use of NMR techniques to determine petrophysical properties of reservoirs has been described in many previous works1,2. But, together with Gamma Ray logs, thin sections and capillary pressure curves, NMR can contribute further to the characterization of sedimentary environments and porosity systems.

In this work the results of the above mentioned techniques are presented. Almost 40 plug samples form a cored well in the Formation of Cretaceous age in Southwest Venezuela have been measured and described according to four sedimentary facies. We have found that the shape of the NMR T2 distributions and thin fine section images of each samples show a pattern related to the sedimentary facies the samples belong to. Another contribution of this work is that, unlike other reservoirs in Venezuela, the shape of the T2 distributions for the sample set can have one, two, three or four maxima or peaks depending on the porosity's system type e.g. intracrystalline, intercrystalline, fractures, synsedimentary fractured and vugs.

The correspondence between sedimentary facies and T2 distributions allows us to classify the rock quality as a function of the porosity, bound fluid and free fluid volumes expressed in the well known Timur-Coates permeability equation determined in each facies.

The results contribute to reduce the uncertainty in the petrophysical understanding of the reservoir and to improve the application of NMR technique in the sedimentology. Specifically, the relationship between T2 distribution patterns, thin section images and depositional environments extend the applications of NMR techniques beyond the classical determinations of petrophysical variables and fluid properties.
Efficient and Accurate Estimation of Permeability and Permeability Anisotropy from Straddle-Packer Formation Tester Measurements Using the Physics of Two-Phase Immiscible Flow and Invasion
Authors: Angeles R. , Lee H. J. , Alpak F. O. , Torres-Verdín C. , Sheng J.
Published: December 2007

This paper describes the successful application of a novel methodology to estimate permeability and permeability anisotropy from transient measurements of pressure acquired with a wireline straddle-packer formation tester. Unlike standard algorithms used for the interpretation of formation tester measurements, the methodology developed in this paper rigorously incorporates the physics of two-phase immiscible flow as well as the process of mudcake buildup and invasion. The effects of supercharge, skin, and convective transport of salt are also explicitly included in the estimation algorithm.

An efficient 2D (cylindrical coordinates) implicit-pressure explicit-saturation finite-difference algorithm is used to simulate both the process of invasion and the pressure measurements acquired with the straddle-packer formation tester. Initial conditions for the simulation of formation tester measurements are determined by the spatial distributions of pressure and fluid saturation resulting from mud-filtrate invasion. Inversion is performed with a rigorous Levenberg-Marquardt nonlinear minimization algorithm. Sensitivity analyses are conducted to assess non-uniqueness and the impact of assumptions on rock-fluid and mud properties such as fluid viscosity, capillary pressure, relative permeability, mudcake growth, and time of invasion.

Applications of the estimation algorithm to noisy synthetic measurements include homogeneous, anisotropic, layered, and multi-layered formations, for both low- and high-porosity rocks. We also study the effect of unaccounted impermeable bed boundaries on the inversion results. For cases where a-priori information can be sufficiently constrained, our inversion methodology provides reliable and accurate estimates of permeability and permeability anisotropy.
Numerical Well Testing: A Method to Use Transient Testing Results in Reservoir Simulation
Authors: Kamal M. M. , Pan Y. , Landa J. L. , Thomas O. O.
Published: December 2007

Transient testing is facing a challenge to have the information it provides incorporated in numerical simulators used to predict reservoir performance. Of greater importance, the lack of using the large number of dynamic in-situ reservoir parameters that can be determined from transient tests deprives operators from valuable data they can use to improve their reservoir management efforts. The main reason for the problem is that transient testing technology, developed largely via analytical solutions, provides average reservoir parameters not suited to the numerically discretized environment of current reservoir simulators. Previous efforts to include transient testing data in numerical reservoir simulation studies focused on history matching the pressure behavior during the test on a Cartesian-type plot just like matching stabilized production rates and pressures. Such approach neglects the wealth of information contained in the transient behavior of the tests.

A method called Numerical Well Testing (NWT) is proposed in this paper to preserve the information obtainable from traditional well test analysis and deliver it in a form suitable for direct use in numerical reservoir simulation. By using this method petroleum engineers will not shy away from using transient testing results just because they do not know how to incorporate averaged values in their discretized reservoir model.

NWT is a systematic method that consists of five steps starting with traditional well test analysis, locally refining grids based on the analysis results, modifying full field numerical models, upscaling, validating the updated model with production data, and predicting future reservoir performance. Details of how to accomplish each step are presented in the paper.

NWT was applied to field cases to demonstrate the applicability of the method and proved that incorporating results from the proposed NWT procedure improved reservoir description. Descriptions enhanced by NWT matched not only well test data but also field production data, and predicted different reservoir performances from those obtained via matching only production data. The paper concludes by describing the software developments needed to make NWT a routine analysis method.
Logging Tool Enables Fracture Characterization for Enhanced Field Recovery
Authors: Bailey J. R. , Sorem W. A.
Published: December 2007

ExxonMobil has developed a fracture mapping tool that uses acoustic methods to infer the geometry of induced hydraulic fractures. This tool may be run in the treatment well during fracturing, or it can be used in one or more offset monitoring wells. This tool, "TABS" for Triaxial Borehole Seismic, consists of an array of three triaxial geophone receivers, a telemetry sub to transmit the data to surface in real time on conventional 7-strand wireline, and an interface to a Gyrodata survey tool to provide the tool orientation when clamped. The tool subs are interconnected with "flex links" that are rigid in rotation but flexible in bending to allow each clamp arm to make independent coupling to the wellbore casing. The overall design is that of a logging tool, facilitating application via wellhead lubricators.

The geometry of the stimulated fracture has a significant impact on well productivity and recovery. In many applications, the reservoir depletion pattern is highly dependent on this geometry. Some key interactions between productivity and fracture geometry include: Well spacing is determined by the fracture length, formation properties, and depletion plan.Within this spacing constraint, well locations are determined by the induced fracture azimuth. Wells are placed to reduce interference among producers and to maximize conformance.Fracture height growth out of zone may lead to more costly stimulation treatments and lower well productivity. Modifications to the treatment design and adjustments to the selection of perforated intervals may increase well performance.

Working with the ExxonMobil Production Company, the TABS tool has been used to monitor 32 fracture treatments in 16 well entries. Results from several of these field applications will be used to describe the TABS technology and to demonstrate fracture geometry measurements.