bluuebunny/crossref_metadata_2025 huggingface dataset:
Ensuring Effective Stimulation Treatments in Difficult Completions
Authors: Willemse M. , Mostafa O. , El-Ashry M. , Abdallah I. , Sattar A. A. , Waheed A. , Conrad B.
Published: December 2007

Achieving effective stimulation across zones not readily accessible is a common challenge in the oilfield. Several authors1-3 have presented case histories in which horizontal wells completed with slotted liner, gravel pack, internal gravel pack, or plain sand screens were difficult to stimulate because there was no easy way to effectively remove drilling fluid filter cake from the wellbore walls. Similar inaccessibility is encountered when dealing with straddled completions, where out of necessity, the producing zone is placed behind straddle packers that are extremely challenging to reach. Another accessibility problem is encountered when a "fish" becomes caught up across the perforated interval and accessibility is again denied.

Should such wells produce trouble-free and meet expectations, there is not much to ponder; but if not, the options for executing an enhanced stimulation treatment have been limited. Generally, treatment has consisted of pumping and squeezing away the treatment into the perforations and hoping for the best. The preferred technique is to improve the injectivity into the perforations by "spotting" reactive fluids at the perforations or using some type of mechanical action such as "perforation jetting" to break up blockages in the perforation tunnels. This is only possible when perforations or pays are accessible through the wellbore.

These problems become more complicated if the zones of interest are sandstone reservoirs. A study4 in the late 1990s revealed a success ratio in the 30–40% range when treating such formations.

This paper primarily deals with a case history in which a sandstone reservoir, not previously matrix-acidized, was producing at sub-par rates, eventually declining to a negligible production status. The zones were completed between straddle packers and were only accessible through a sliding side door (SSD), 100 ft above the perforations.

The prudent decision was to stimulate, but make all efforts to maximize the chances of success. Apart from applying the best practices in sandstone acidizing technology, a true fluidic oscillator (TFO) was included as a stimulation tool. This tool provides a continuous pressure pulse in the fluid system that allows solids buildup within the perforations to fatigue and break up while the acid system works on the rock matrix.

The results from the treatment of this well were exceptional and will be detailed in this paper. The production improvement was 10-fold over its prestimulation performance.
A Decision Analysis Approach to Hydraulic Fracture Optimization in the W31S Stevens Oil Zone, Elk Hills Field, California
Authors: Agiddi D. O.
Published: December 2007

Since 1999, hydraulic fracture stimulation in the layered W31S Stevens reservoir, Elk Hills, has increased productivity of new infill wells. One to six months increase in production of well over 300 percent in barrels of oil equivalent per day (BOEPD) has been achieved. Since 2002, optimization in treatment fluid has lead to a change from conventional borate cross-linked, guar-based polymers to new gel technologies with low polymer concentrations designed to minimize formation damage - an important consideration for the declining reservoir pressure and the low permeability rock in W31S sand. New available fluids combine stable downhole rheology with enhanced visco-elastic properties to provide good proppant transport capabilities.

Infill drilling activity in the W31S zone has recently moved from the flank areas of the 31S structure to up-dip locations with higher vertical rock stress difference, less thick pay, and higher gas-to-oil ratios. Different fracture monitoring and diagnostic data, including a down hole treatment pressure survey, has been acquired to characterize fracture growth profile and to optimize the W31S fracture design model. Review of recent well performance and treatment data suggests that, though productivity gains are realized from improved clean-up characteristics of the new fracturing fluids, achieving full vertical coverage and design conductivity remains a great challenge. This has huge implications for the economics of the development drilling in the up-structure locations.

This paper introduces a quantitative fracturing treatment option model as a useful communications tool for selecting the treatment with the best chance for economic success.
Achieving Low Emissions in an Internal Combustion Engine Using Off-Spec Produced Fuel Gas
Authors: Cassinis R. , Larson W.
Published: December 2007

Tidelands Oil Production Company was producing associated gas containing high levels of CO2 that did not meet the specification of the local utility and was being flared. An alternative use for the gas was to fuel a 2,000 horsepower internal combustion engine to drive a high-pressure water injection pump. However, the strict emission level requirements for NOX, CO and VOCs at the Southern California location required that a new emissions control design be configured and used. This paper will discuss the system design, economics and the steps taken to enable the internal combustion engine to meet the strict emissions standards of the region while using off-spec, high CO2, produced gas.
Analysis of Completion and Stimulation Techniques in a South Texas Field Utilizing Comprehensive Reservoir Evaluation
Authors: Larkin S. D. , Pickrel H. M. , Lattibeaudiere M. G. , Marti S. K. , Atwood K. , Poe B. D.
Published: December 2007

This paper will evaluate the efficiencies of completion methods in a South Texas field utilizing the latest techniques in post fracture production analysis. Stimulation effectiveness for each frac stage in ten multi-zone wells is evaluated.

Effective values for reservoir and fracture parameters including porosity, permeability, propped fracture half-length, fracture conductivity and fracture face skin will be derived using production analysis techniques and will be compared for the different completion methods employed. The holistic model will incorporate the geological, petro-physical properties of the formation and production logging data.

Actual stimulation and production data from ten wells in the same area are used in this analysis. Five of the wells were completed in single-stage fracture stimulation across multiple perforated intervals. Five wells were completed with two-stage fracture stimulations across multiple perforated intervals. The multiple layer fracturing technique was utilized in all wells. The study will derive the effective reservoir and fracture parameters using production allocation for each interval in the multiple interval wells.

This paper will compare the different completion techniques using this methodology and will discuss a predictive model for future stimulation work in this area. This methodology will also help in identifying under-stimulated zones in existing wells that may be candidates for re-fracturing.
Water Control Problems and Solutions-Los Angeles Basin Statistics and Case Histories
Authors: Swanson G. , Ershaghi I.
Published: December 2007

This paper presents a statistical overview of water control issues currently important to Los Angeles Basin operators of high water cut, mature, turbidite waterfloods. Certain observations, analyses and conclusions may be of interest to others working with high water cut fields. Case studies demonstrate reasonable costs and economic payouts for water control efforts.

Several LA Basin operators contributed water control-related information to a consortium study sponsored by the the U S DOE PUMP program and the California Energy Commission and managed by the Petroleum Technology Transfer Council. Data from seven fields, which together account for more than half of LA Basin's production, were analyzed in order to identify key factors which contribute to water control problems and solutions.

Information for wells with poor or good performance were obtained from the operators and analyzed. Parameters which differed significantly among categories of injectors and producers were characterized. In total, 60 injectors and 67 producers were analyzed in detail, yielding several statistics and observations of interest.

Water control strategies were also analyzed as part of this study. Seventeen water control jobs, costing $25,300 on average, resulted in an average payout of 7.1 months. Operators’ policies regarding computation of water production, treatment and re-injection costs were reviewed in detail, resulting in a weighted average cost of $.23/bbl of water produced. Operators investing more than $.02/bbl in water control were observed to hold water cut increases to less than 0.2%/year, while those spending less than $.01/bbl experienced annual water cut increases in excess of 0.4%/year.

All statistics highlighted above were extracted from several databases that allowed many more analyses to be conducted, including individual operator and/or field comparisons to basin-wide averages.
What Would Be Different if the Exploitation Started Today - Comparison to a Real Field
Authors: Salomão M. C. , Peisino R. O.
Published: December 2007

Marimbá Field, located in Campos Basin, Brazil, has produced since 1985 more than 220 million bbl of light oil, from a high permeability friable sandstone reservoir, corresponding to half the recoverable volume. At the time when the production system was installed the reality was really different: the technology of horizontal wells was still at its dawn and hence the field was developed with vertical and directional wells; at the same way, the technology of sand control was not as efficient as today, and it was adopted a strategy of limit rate, in order to keep the productivity index, and to prevent the high level of sand production and the formation of water conning. These constraints were determinant to the shape and the number of wells, the diameters of tubings and rises, and the facilities of the production system. If we had the same field to initiate the exploitation today, the development plan would be quite different: the system would be probably composed by a little number of horizontal wells, sand-controlled, with higher rates of production; with a cheaper platform, it would be recovered almost the same volume of hydrocarbons, in a shorter life of production, with higher economic index. In present work we make this comparison in a real case, using the reservoir simulation tool to predicting the production profile. The strong contrasts in the results inspire the proposal of new opportunities, by changing the current development plan, in order to anticipate the recover of fluids, and to reduce the operational costs, maximizing the profits of the concession.
Automatic History Matching of Naturally Fractured Reservoirs and a Case Study
Authors: Cui H. , Kelkar M.
Published: December 2007

In naturally fractured reservoirs, the fracture intensity (density) control the fracture permeability and the dimensions of matrix blocks, and hence govern the reservoir production performance and oil recovery process. In the last decade, great progress has been made in the characterization of natural fracture system of naturally fracture reservoirs. The statistical fracture intensity model can be constructed by integrating the direct local data, such as core and image log data, and field scale data derived from seismic attributes, fault-related-strain-field, structural information (curvature), etc. The static fracture model must be converted into flow simulation model for dynamic simulation, and must be adjusted to honor the production history to perform production performance prediction and optimal development planning.

This paper discusses the development of a novel method of conditioning the fracture intensity model to the production data. This is achieved by making the sensitivity coefficients available of production data with respect to fracture intensity through the building of correlations between fracture intensity and fracture permeability and fracture/matrix coupling factor.

Gradient simulator and adjoint methods are used to calculate the sensitivity coefficients of production data to the parameters of fracture and matrix blocks. Both two methods usually involve solving of a great number of matrix equations. Sparse LU decomposition is used to solve the matrix equations to improve the computational efficiency of sensitivity coefficient. To the best of our knowledge, the particular implementation of the sparse LU direct methods in automatic history matching is new to the petroleum engineering literature.

The proposed method and developed software is validated by applying to a giant Middle East carbonate naturally fracture reservoir.
Innovative Approach to Multiple Gas Fields Simulation through the Application of the Mixed Black Oil and Compositional Formulation
Authors: Bargiggia C. C. , Giordano D. , Monico C.
Published: December 2007

A mixed formulation technique, coupling compositional and black oil mode, was used in a regional simulation model to study the associated liquid hydrocarbon production of two wet gas fields still in the development phase in communication through the aquifer with other gas fields already on production.

Initially, a regional 3D black oil model was built. The history match was carried out with the main target to reproduce the measured pressures in all the fields.

Since it was necessary to predict the associated liquid hydrocarbon production of the new fields, their relevant model zone was converted to compositional formulation in the forecast simulation runs.

With the mixed model approach, different formulations coexisted in the same model with the possibility to be switched on or off during the simulation run. The advantage was to perform a local compositional control in the production forecast, maintaining black oil simulation in the remaining part of the model. The method was validated by comparing the mixed formulation production profiles to the ones obtained with the black oil simulation.

This technique enabled us to predict the rate and the characteristics of the hydrocarbon stream in the two gas fields. A further benefit was a remarkable saving of the CPU time, due to the use of black oil simulation outside the two new gas fields.
Integrated Field Development for Effective Scale Control throughout the Water Cycle in Deep Water Subsea Fields
Authors: Jordan M. M. , Mackay E. J.
Published: December 2007

Scale control in produced fluids as water follows the cycle of injection, production, processing and reinjection in oil production facilities is, in many cases, critical to the effective production of hydrocarbons in a safe, economic and environmentally acceptable manner.

This paper focuses on the challenges to scale control in deepwater reservoirs, and describes the scale control measures that are designed into the field development plan based on the integration of reservoir simulation, completion design technology and production chemistry. Emphasis is placed on the need to consider the full life cycle of the field, considering a range of development scenarios, such as water flooding with seawater, desulphated seawater, produced water re-injection, aquifer water injection and primary depletion.

Advanced fluid flow and reaction calculations that account for in situ scaling reactions and the impact on the produced brine chemistry are used to provide data to refine the economic models used to identify the optimum scale management technologies. The various functions that must be carried out for effective scale management at the CAPEX and OPEX phase are outlined.

The paper clearly demonstrates how, by using an integrated team that includes personnel drawn from operating company, chemical service company and research institute backgrounds, a multi-disciplinary approach may be used to integrate engineering and chemical solutions to effectively arrive at the most economic scale control programme for these challenging fields.
Screening of Reservoir Types for Optimisation of Intelligent Well Design
Authors: Ebadi F. , Davies D. R. , Reynolds M. , Corbett P. W. M.
Published: December 2007

Intelligent completions focus on delivery and management of production flexibility. Intelligent Well systems Technology (IWsT) deliver the ability to monitor and control production without the need for conventional interventions. Installation of intelligence at the well level is not always a guarantee for success - it must be shown to add value to gain acceptance. This paper uses a new workflow to investigate the premise that some reservoir types are inherently more suited to IWsT application than others.

A series of generic reservoir scenarios, based on property distributions derived from real field data and operational oilfield models, were built. These geological scenarios were tested to determine the added value from IWsT compared to standard completions. Situations in which IWsT proved particularly successful, and situations which showed little or no value, have been identified.

Results show that IWsT can control uneven, invading fluid-fronts that have developed along the wellbore length due to permeability differences, reservoir compartmentalisation or different strength aquifer/gas cap support. Downhole Interval Control Valves (ICVs) are capable of managing wellbore friction effects and such differences in zone pressure along the wellbore. Oil recovery factors improve and water production rates reduce with the correct choice of the number of ICVs installed and their location along the length of the wellbore. However, the degree of improvement is dependent on the reservoir type (Layered, Faulted, Channelised, etc.) and the distribution of porosity and permeability within it. This study provides a new look at the applicability of IWsT in a wide range of reservoir types.

In the next stage, a range of realizations of a reservoir model were generated, so that the degree of heterogeneity was increased systematically in the models by changing the Coefficient of Variation and the Correlation Length. The added value from an intelligent well installed in these reservoir realisations was evaluated.

The results were analysed in terms of correlation length vs. coefficient of variation. A potential IWsT applicability envelope was developed. These plots can be used as an initial screening tool for deciding when, and when not, to implement IWsT.

The final decision on whether to install such equipment will be made by an engineer making a detailed technical and economic analysis for the particular case being studied. This last phase is outside the scope of this paper.
The Impact of Pertinent Parameters on the Design of Hydraulic Fracturing in Gas Condensate Reservoirs
Authors: Carvajal G. A. , Danesh A. , Jamiolahmady M. , Sohrabi M.
Published: December 2007

Fracturing is the most common well stimulation technique in gas condensate reservoirs. Flow of black oil and dry gas in induced fracture systems has been widely studied by numerical simulation, core-flood and well tests. However, the flow behavior in fractures surrounding a gas condensate well, which could be significantly different to that of conventional systems, has not been fully understood. Most of the available literature has quantified the negative effect of condensate banking and inertial (non-Darcy) flow on well productivity, giving a pessimistic view of the gas rate in these systems. The above studies have neglected improvement in the gas and condensate relative permeability by increasing rate due to positive coupling of the two phases.

In this work, measured values of permeability, single-phase inertial factor and relative permeability of a propped fracture were used to evaluate the effect of pertinent parameters on fracture performance more realistically. A reservoir simulator was used to develop realistic models of flow in fractured systems. A comprehensive sensitivity analysis on the impact of fracture characteristics on well productivity for different fluids and rock properties was conducted. The results demonstrated that not only inertia was important but also positive coupling strongly affected the flow performance. In particular for a tight formation, whereby fracturing is most effective, positive coupling in the matrix can overcome negative inertia in the fracture region. The results also reveal the important contribution of the fracture width, as wide fractures reduce the inertial effect significantly. Furthermore, we will show that increasing the fracture length does not necessarily lead to higher gas well productivity as there are optimum values for any given set of parameters.
Field Experiment of ECBM-CO2 in the Upper Silesian Basin of Poland (RECOPOL)
Authors: Pagnier H. J. M. , van Bergen F. , Kreft E. , van der Meer L. G. H. , Simmelink H. J.
Published: December 2007

The RECOPOL project is an EC-funded research and demonstration project to investigate the technical and economic feasibility of storing CO2 permanently in subsurface coal seams. This is considered to be an option for CO2 sequestration, which will be required to meet the Kyoto protocol. The main aim is to demonstrate that CO2 injection in coal under European conditions is feasible and that CO2 storage is a safe and permanent solution before it can be applied on a larger scale in a socially acceptable way. An international consortium of research institutes, universities and industrial partners is carrying out the project activities. This is the first field demonstration experiment of its kind in Europe. The development of the pilot site in the Upper Silesian Basin in Poland began in summer 2003. One of the existing coalbed methane wells was cleaned up, repaired and put back into production. A new injection well was drilled at 150 m from the production well, the distance being based on the available amount of CO2 and project time. After completion of the well with casing, cementing and perforations, the perforated zones were tested. Activities in autumn 2003 included the finalizing of the injection facilities. Production was started in the first half of June 2004 to establish a base line gas production without CO2 injection. First injection tests took place in the first week of July 2004. During the injection period the process was monitored to assess any potential, although unlikely, leakage of CO2 to the surface.
Integrated Modeling of the El Furrial Field Asset Applying Risk and Uncertainty Analysis for the Decision Making
Authors: Acosta L. M. , Jiménez J. , Guedez A. , Ledezma E. A. , Bello J. A. , Millán A. J. , Guzman M. , Marin E. , Gómez F. J. , Herrera I. , Córdoba P.
Published: December 2007

The El Furrial field is one most important hydrocarbon giants of Venezuela. It's located at the north of the Monagas State and it handles approximated 45 % of the production of this area. It was discovered in 1986 and its characteristic makes it unique. The strategy of development has been supported by the combined injection of miscible gas and water; this has allowed maintaining the production plateau of 400 MBPD of 28 ° API oil. A transcendental advance in the characterization of the field was done with a new dynamic model called V9, what promoted the evaluation of new development scenario.

This paper presents one of the first integrated development plan built by PDVSA; focus on the Integrated Modeling of the Asset, considering risk and uncertainty analysis in the decision taking. The project was developed under a philosophy of collaborative work and changing the way of thinking from deterministic to probabilistic. The Project was executed by a multidisciplinary team integrated by personnel of the core areas of the asset, creating a milestone in the traditional way of working. This integration allowed evaluation through statistic and expert interview, the uncertainties associated to the variables involved in the evaluated scenarios. Huge reduction of capital expenses related with the grow of facilities were obtain due to the estimation of production profiles based on risk and uncertainty analysis. As a result of this analysis a decision matrix was built, with the recovery factor, investment, qualitative risk factor, and economic indexes, which were evaluated to decide the optimum development plan.
The Kansas Arbuckle Formation: Performance Evaluation and Lessons Learned from More Than 200 Polymer-Gel Water-Shutoff Treatments
Authors: Portwood J. T.
Published: December 2007

Polymer gels used for shutting off unwanted water in producing oil wells are certainly no stranger to the Arbuckle dolomite formation in Kansas, but in years past, they have delivered short-lived results and have been only marginally successful. In November 1997, that all changed after a unique design strategy utilizing proven polymer gel technology caused dramatic increases in oil production that resulted from shutting off a significant volume of water from a well located in the Bemis-Shutts field. Since that time, more than 200 wells have been treated for about 35 different operators with a greater than 95% success rate. Thousands of barrels of incremental oil at each treated well are being realized, and hundreds of thousands to millions of barrels less water are being produced from each treated well, than otherwise would have been produced without the treatment. These treatments are extending, by several years, the economic life of many Arbuckle wells, and are bringing shut-in wells back to life.

This paper will report lessons learned from applying polymer gel water shut off technology to the Arbuckle formation, and present statistical data derived from a detailed database that has been maintained throughout the project. In addition to using the database as a tool to quantify results and further improve job performance, it is also being used to improve the predictability of response to treatment. Post-treatment oil and water production performance and treatment longevity will be compared to several variables like polymer gel treatment volume and injection pressure. The paper will also discuss how polymer injectivity and post-treatment well performance changes from place to place within the Arbuckle formation. Finally, treatment economics including job cost, payout time, revenue gain from increased oil and decreased water production, and return on investment will be presented.
Capillary Interaction of Different Oleic and Aqueous Phases Between Matrix and Fracture Under Ultrasonic Waves
Authors: Hamida T. , Babadagli T.
Published: December 2007

Various mechanisms may be responsible for enhancing the flow of oil through porous media in the presence of an acoustic field. Major capillary related mechanisms are peristaltic transport due to mechanical deformation of the pore walls, reduction of capillary forces due to the destruction of surface films generated across pore boundaries, coalescence of oil drops due to the Bjerknes forces, oscillation and excitation of capillary trapped oil drops, and sono-capillary effects. This study aims at analyzing the influence of high-intensity ultrasonic radiation on spontaneous imbibition of surfactant and polymer solutions into porous media.

A series of laboratory experiments were performed using cylindrical Berea sandstone samples with all sides (co-current imbibition) and only one side (counter-current imbibition) open to flow contacting with the aqueous phase. Emphasis was given to the fluids of special interest to well stimulation and EOR applications. Anionic and nonionic surfactant solutions above and below the CMC were chosen to evaluate the effects of ultrasonic waves on the imbibition of low interfacial tension fluids and microemulsions. Xanthan gum solutions were also used as an aqueous phase to examine the effects of ultrasonic waves on the imbibition of viscoelastic fluids. The oil-saturated cores (crude and processed oil) were placed in an ultrasonic reaction chamber, and brought into contact with the aqueous phase. The recovery rate due to capillary imbibition was monitored against time.

We compared the capillary imbibition recoveries with and without ultrasonic waves. A substantial increase in final recovery (up to 25% OOIP) and minor increase in recovery rate was observed when ultrasonic waves were applied to the surfactant solution. High intensity ultrasound was observed to enhance surfactant solubility and reduce adsorption onto the rock matrix. A small increase in the ultimate recovery was observed at low polymer concentration. At higher polymer concentrations, however, the difference rose significantly (up to 12% OOIP).
Estimation of Water Content in Sour Gases
Authors: Mohammadi A. H. , Samieyan V. , Tohidi B.
Published: December 2007

Estimating the water content of natural gases is necessary in many chemical and petroleum engineering processes, e.g., calculating the amount of water condensed in a pipeline for designing hydrate inhibition strategy. An empirical method based on correction of ideal model for estimating the water content of sweet natural gases in equilibrium with the liquid water or ice has been developed. This predictive method estimates the water content of sweet natural gases using the water/ice vapor pressure, the system pressure and temperature. In order to extend the capabilities of the new approach to sour gases, a correction factor is proposed for taking into account the effect of acid gases on the water content. The new approach has been developed using the predictions of a comprehensive thermodynamic model as pseudo experimental data. The data on water content of methane with different concentrations of carbon dioxide and hydrogen sulfide were generated and fed to a multi-dimension regression program. The predictions of the developed empirical correlations are in good agreement with independent experimental data, demonstrating their reliability in estimating the water content of natural gases. Finally, a discussion is made on determining the location of water condensation along a pipeline using a simplified energy balance equation and the method developed in this work.
Application of Tracer Technology for Optimising RKF Miscible Gas Injection Recovery - Field Case
Authors: Cubillos H. , Torgersen H. , González O. , Lamela M.
Published: December 2007

The paper shows a field application of gas tracer technology for improving the reservoir description and optimising RKF miscible gas injection project.

In a miscible gas injection process, the dynamic characterisation of flow paths is critical. Gas tracer technology is emerging as a powerful tool to quantify reservoir properties that control gas displacement processes. The Capillary Absorption Tube (CAT) combined with Gas Chromatography with Mass Spectrometer detection (GC/MS) method has significantly improved the ease and safety of tracer sample collection and transport, providing cost-efficient information.

RKF field, operated by the Sonatrach/CEPSA Association in the Berkine Basin of Algeria, is producing mainly from TAGI formation by peripheral down dip miscible gas scheme. Perfluorocarbon gas tracers were injected as part of the initial 1997 reservoir management plan and monitoring allowed to building good tracer production profiles.

CEPSA has developed an "integrated tracer-reservoir performance analysis" program consisting of qualitative and numerical analysis techniques. Operational plan modifications are developed from this program to optimise field performance. Slim tube and sector model, were built with VIP™ to evaluate tracer flow simulation under miscible gas injection conditions. Following these studies, tracer breakthrough times were history matched in the full field simulation model.

Some operational changes made to gas injection patterns, as a result of the tracer monitoring program, have increased oil production and improved recovery.
A New Two Phase Pseudo Pressure Approach for the Interpretation of Gas Condensate Well Test in the Naturally Fracture Reservoir
Authors: Mazloom J. , Kelly R. T. , Mahani H.
Published: December 2007

This study introduces a novel approach in the use of two-phase pseudo-pressures for the interpretation of gas condensate well test data in naturally fractured reservoirs. In a gas condensate reservoir, where the pressure falls below the dew point in the vicinity of a well, calculation of pseudo-pressures requires knowledge of the relationship between condensate saturation and pressure in all regions of the reservoir. An equation that relates condensate saturation to pressure is developed in this study for the region away from the well where condensation occurs but the condensate is immobile until its critical saturation is reached. A different equation, based on steady state flow, is presented for the region near the wellbore where the condensate is mobile. A single-phase, pseudo-pressure equation is used for the region of the reservoir further away from the well, where the pressure is still above the dew point pressure. This approach is verified using well test data generated with a compositional simulator, and real PVT data from a gas condensate field. Analysis of the computer-generated data yields dual porosity reservoir parameters and condensate saturation profile that are similar to the ones used in, or produced by simulation. It is also shown that the majority of the condensate dropout occurs in the fractures and not in the matrix in a dual porosity system and that the saturation profile in fracture media governs the build-up derivative curve. The amount of condensate in matrix has no effect on the derivative curve.
Monitoring PVT Properties Derivatives Ensures Physically Sound Tuned EoS Behaviour over the Entire Operating Conditions Range
Authors: Gaganis V. , Varotsis N. , Nighswander J. , Birkett G.
Published: December 2007

In this work, a method is proposed for guiding the Equation of State (EoS) tuning procedure against a set of laboratory measurements such as that a physically sound behaviour of the model can be produced throughout the operating compositions and conditions range.

The derivatives of each individual EoS PVT prediction with respect to each of the input parameters are directly evaluated and subsequently utilised for verifying the behavior of the model throughout its applicability range. Thermodynamically sound profiles of the model derivatives which should be respected during tuning are also provided.

By applying the Taylor expansion method, we demonstrate how typical EoS tunings can lead to significant prediction errors while moving along the multidimensional surface as conditions and composition vary during production.
Preventing Annular Flow after Cementing, One Pulse at a Time: Offshore Gulf of Mexico Cement Pulsation Field Results
Authors: Aslakson J. , Doherty D. , Smalley Ed
Published: December 2007

The initial offshore application of cement pulsation to prevent annular flow/pressure after cementing has been successfully performed in the Gulf of Mexico (GoM). This paper describes the methodology and cementing results achieved following application of the cement pulsation technology in multiple shallow offshore GoM casing strings. The compressible volume of the cement column is recorded during the pulsation operation, and this data can provide for surface monitoring of the downhole cement setting process. An overview of the equipment and cement pulsation pre-job design considerations are also included in this paper.
Recent Developments in Homeland Security Laws That Impact Exploration and Production
Authors: Randle J. S.
Published: December 2007

In the aftermath of September 11, 2001, a significant amount of legislation was passed by the U.S. Congress aimed at improving homeland security in the United States. At the same time, the petroleum industry, working with the government, began increasing its efforts to reduce the industry's vulnerability to terrorism. Today, petroleum companies face the burden of implementing new security measures and complying with new security laws which often are complex, overlapping in scope, and enforced by multiple agencies. This paper provides an overview of industry-sponsored security initiatives and relevant homeland security laws and offers practical solutions for companies trying to minimize liability risks related to terrorism.
Analytical Technique for Allocating Production to Subzones to Evaluate Prospect Candidates in the Terminal Zone of Fault Blocks III and IV, Wilmington Field, CA
Authors: Bust V. K. , Phillips C. C. , Hara P. S.
Published: December 2007

The analytical technique integrated the 3D geologic model, reservoir and production and injection information into a single Project database for a study area that comprised 109 acres in Fault Blocks III and IV in the Wilmington Oil Field, California. The result was the creation of a new reservoir evaluation tool that enables the user to quickly evaluate reservoir performance and potential development well locations. It provided a "snapshot" picture of well production or injection on a subzone basis for any selected time interval without using a simulator. The Project database is flexible because it utilizes whatever well, reservoir characterization, production and geologic information that are available to provide a more robust analysis than typical cumulative production and injection bubble maps.

An empirical mathematical algorithm was created to allocate the commingled total well fluid production to subzones. The algorithm allocated subzone production based on: 1) fraction of completed interval open in each subzone; 2) net sand weighted-value; and 3) flow capability (KH) weighted-value. The subzone flow capability (subzone KH) was calculated by multiplying the subzone average core air-permeability by the net sand thickness for each subzone. The allocation algorithm was developed for single fluid flow and not for fractional fluid flow. Fluid flow trends were identified by analysis of the produced oil and water volumes, WORs and water injection volumes tracked over selected time intervals and well completions. Volumetric analysis was used to estimate remaining oil in-place for each subzone and drainage areas. Pseudo oil saturation maps were generated to visually site and evaluate infill waterflood development well prospects.

The validity of the allocation algorithm was confirmed by the reasonable agreement found between the measured and predicted percent injection splits. This reservoir evaluation-screening project demonstrated the potential for a field-wide application to identify and prioritize drilling prospects.
Technical Enhancements Increase the Life and Add Value to New and Existing Wells by Use of Solid Expandable Tubular Solutions
Authors: Wallace J.
Published: December 2007

As completions become more complex and operating environments more severe, deeper, hotter and in higher pressure, exploration and field development solutions are needed that provide results and improve well savings. Five years of improving the application record of solid expandable tubulars with solution enhancements have resulted in greater value and mitigated risks for end users. This enabling technology has been used to address a myriad of drilling situations and downhole conditions as part of the well design, as a planned contingency option and as a last resort. Currently, the technology consists of several expandable systems that include cased-hole liners, openhole liners, openhole cladding systems and flexible cladding systems. These systems have been used to solve problems associated with borehole instabilities, pore-pressure/frac-gradient issues, wellbore tapering and perforated sections to name a few.

The ability to run, clad and expand into the base casing efficiently and reliably is paramount considering the increase in well pressures, production depths and drilling costs. An application legacy of over 300 installations has led to system enhancements and process modifications that have helped increase reliability and efficiency. These changes to solid expandable systems help operators reach and produce reserves that previously were unattainable due to drilling conditions and economic constraints, provide flexibility for exploration well uncertainties, reduce nonproductive time, provide larger corrosion resistant production conduit and reduce well costs by slimming well design.

This presentation will discuss improvements made to solid expandable tubular systems and how this technology can increase the life of, and add value to, both new and existing oil and gas wells.
CO2 Foam Behavior: Influence of Temperature, Pressure, and Concentration of Surfactant
Authors: Liu Y. , Grigg R. B. , Svec R. K.
Published: December 2007

A high-pressure, high-temperature (HPHT) bubble chamber apparatus is used to determine carbon dioxide (CO2) foam stability, interfacial tension (IFT) between HPHT CO2 and surfactant solutions and critical micelle concentration (CMC). Chaser CD1045™ (CD) was used in this study. In this study, changes of temperature from 25 to 75°C, pressure from 800 to 2000 psig, and surfactant concentration from 0.005 wt% to 1 wt% were tested for foam stability, IFT and CMC. The relationship of foam stability and IFT is also discussed in this paper.

IFT decreased with surfactant concentration below the CMC and was essentially constant above the CMC, increasing with the increase of temperature and the decrease of pressure. Stability of CO2-foam is surfactant concentration-dependent. The coalescence of bubbles was observed only at CD concentration of 0.005 wt%, well below the CMC at 25°C and 1500 psig. The foam was stable under all tested temperatures at surfactant concentrations of 0.1 wt% and above, and decreased with increase of temperature at surfactant concentrations of 0.05 wt% and below at 1500 psig. The foam was stable under all tested pressure at surfactant concentrations of 0.025 wt% and above, and decreased with increase of pressure at CD concentrations of 0.005 wt% at 25°C, and similar behaviors were observed at high CD concentrations at 75°C.
Incremental Improvements in 50:50 Poz Cementing Yields Enhanced Properties & Cost-effective Application
Authors: Fasesan O. A. , Heinze L. R. , Walser D. W.
Published: December 2007

For nearly 50 years, admixtures of 50:50 Class H (or Class C): Pozzalon with 2% bentonite have functioned effectively worldwide as lightweight slurries for situations where heavier completion cements posed a risk of exceeding low fracture gradients in a particular wellbore.Pozzolanic materials are lightweight, and effectively combine with calcium hydroxide that is liberated during the hydration of Portland cement.Historically, the 2% bentonite has been utilized to assist in the specification of relatively high water-to cement ratios, and therefore lighter slurry density, without the generation of excessive free water as the cement progresses though the setting process.Though the bentonite has fulfilled the role quite well, it has two disadvantages: first, its presence in typical cement slurries reduces the effectiveness of a given concentration of most commercially available fluid loss additives.Second, while the 2% (by weight of cement) volume may seem of no consequence, the shipping costs associated with moving tons of the material over a long period of time can be significant.

A project was undertaken to determine whether or not there were other commercially available materials that could substitute for bentonite and yield improved slurry qualities at the same or reduced cost.

Extensive testing of 50:50 slurries revealed that small quantities of sodium metasilicate (on the order of 0.5% by weight of cement) could effectively replace bentonite.Free water was controlled to the same degree, and a synergy with a commonly available fluid loss additive was discovered, allowing either a) less total fluid loss additive for a given fluid loss control tolerance, or, b) better fluid loss control for a given concentration of fluid loss additive.

The testing is summarized, and relative economics associated with the systems are discussed
Treating Uncertainties in Reservoir Performance Prediction with Neural Networks
Authors: Lechner J. P. , Zangl G.
Published: December 2007

In development projects reservoir parameters are only known within certain ranges – a fact that allows various realisations of the subsurface. Because of the computational time involved, not all of the possible parameter combinations can be covered by simulation models to obtain a probability distribution of possible outcomes. Creating a response surface that is based on a reduced number of simulation runs becomes necessary. Such a response surface can be utilized to approximate results for numerous different variations of input parameters. In contrast to the widely used methodology of fitting a polynomial model to the results of a limited number of simulation runs, an approach, where reservoir response is captured by an Artificial Neural Network (ANN) has been investigated.

As a first step the most sensitive parameters which affect the performance of the simulation model are determined with a limited number of model runs. These simulation runs cannot cover each of the possible model realisations, but they are intended to span over the whole range of input parameter variations. By training an ANN on the so gained simulation results, a model, which is able to interpolate between the individual simulation scenarios is created. In this way a large variety of realisations can be approximated by a limited number of reservoir simulation models.

The trained ANN model is used in Monte Carlo Simulation to generate the probability distribution of all possible outcomes. Due to the very low CPU consumption of the ANN, a large number of realisations can be calculated in a short amount of time.
Suggested Guidelines for Mangrove Assessment: An Ecosystem Approach
Authors: Lowrance C. , Myers J. E.
Published: December 2007

When operating in sensitive environments, mangroves and other areas with high biodiversity require broad environmental assessments that consider the full range of habitats as well as ecological processes and functions. The objective of this paper is to provide site managers and other environmental management professionals a method for mangrove assessment that follows the international guidelines of the World Bank, the Convention on Biodiversity, and the Energy and Biodiversity Initiative set forth by Conservation International. These guidelines emphasize the need to incorporate an ecosystem approach so that environmental assessment is broad and considers both long-term and cumulative secondary impacts as well as more immediate primary impacts. In order to accomplish this, mangroves should be assessed at three levels: landscape, habitat, and species health.

Landscape level assessment is necessary to identify historical trends in habitat loss or expansion, fragmentation, or degradation of mangrove over time. Various types of optical satellite imaging (Landsat TM, MSS and Spot XC), radar satellite imaging (ERS-1, JERS-1, and Radarsat), and aerial photography are used to characterize the expansion and contraction of mangrove communities over time.

Habitat level assessments take place in the field and should be designed to yield information about ecosystem or species functioning. Indicators that are discussed include species distribution and abundance, percent canopy cover, seedling densities, faunal biodiversity, hydrology, and soil and water quality.

Species level assessments consider impacts that range in magnitude from localized individuals to entire populations. These assessments use indicators aimed at individual mangrove trees and include diameter at breast height, lenticel densities, leaf morphometrics and chlorophyll concentrations, and the presence or absence of adventitious roots, pneumathodes, and other morphological adaptations that can be used to track both the structural and functional responses of mangrove trees.