bluuebunny/crossref_metadata_2025 huggingface dataset:
Valhall Field - Still on Plateau after 20 Years of Production
Authors: Barkved Olav , Heavey Pete , Kjelstadli Roar , Kleppan Tore , Kristiansen Tron Golder
Published: December 2007

The estimated recoverable reserves from the Valhall field at start of production in 1982 were 250 MMSTB. Now, after twenty years on primary depletion, a total of 500 MMSTB has been produced and additional 500 MMSTB remains to be produced of the original 2.6 BSTB in place. This corresponds to a recovery factor of 40%. Possibilities to increase ultimate recovery have been defined. These will require further insights into the detailed architecture of the field and improved understanding of the reservoir energy and displacement efficiency. Approximately 50% of the drive to date has been from rock compaction. The field is a North Sea Chalk field producing from Tor and Lower Hod Formations, porosity is exceeding 50% in places, some fractured permeability is present, but matrix permeability is generally low, less than 10 mD.

Application of new technology has been fundamental in bringing the field up to current performance. New completion techniques combined with dedicated draw down schedules has been established to reduce influx of the weak chalk formations and reduce well failures. Special well design for a compacting and subsiding environment has also been implemented. Drilling of the overburden has been a key challenge. This has been partly mitigated by detailed geological mapping of problem zones versus structure, lithology, overpressure and wellbore stability analysis, but has also resulted in replacing extended reach wells by the installation of new flank drilling and production facilities. The particular characteristics of the overburden and chalk also pose challenges for data acquisition. Coring technology & practices are very tightly controlled, as is selection of logging devices.

A water flood scheme has been approved based on a successful water flood pilot, but issues related to sweep efficiency, presence of fault and fracture zones and large variation in thickness need to be understood to capture it's full potential. The reservoir will also experience extra water induced compaction and increased subsidence. New logging technology has recently made it possible to define and characterize the fracture system, which combined with a range of surveillance techniques will be key in this work.

Seismic imaging has generally been a challenge at Valhall due to the presence of gas in the overburden. Use of 4C seismic technology has improved this. In addition, the 4D seismic response appears to be very sensitive to production-induced depletion, compaction of the reservoir and subsidence of the overburden and seafloor. Seismic techniques will be critical in future development. For a more detailed review of the first 10 years of Valhall, reference is made to the paper by Ali and Alcock [1].
Relative Permeabilities for Post-Waterflood Depressurisation
Authors: Goodfield Matthew , Goodyear Stephen G.
Published: December 2007

A series of four depressurisation experiments were performed as part of a joint industry project, using core from two North Sea fields. Cores were aged with live crude and following a waterflood were slowly depressurised. The produced fluids were measured, together with in-situ saturation profiles for gas, oil and water. The laboratory results indicated low critical gas saturations, which decrease for slow depressurisation experiments (closer to field rates). However, the ultimate gas saturations left in the cores at the end of the depressurisations was found to be as high as 40% and would represent a significant loss of IOR target if this value were directly applicable to the field. In a previously reported interpretation, this was explained by an unconventional gas relatively permeability function, in which very low gas relative permeabilities persisted to high gas saturations.

A key element of the interpretation of the experiments is the representation of the core outlet boundary condition. New methods have recently been developed for waterflood SCAL studies influenced by capillary end effects, which allow the observed saturation history to be used as the boundary condition, overcoming the limitations of the conventional zero capillary pressure boundary condition. Analysis of the depressurisation experiments shows that movement of gas in the core is dominated by capillary forces. The new methods for imposing an outlet boundary condition were extended to the depressurisation situation and Experiment 4 was reinterpreted. A significantly improved match to the production and saturation data was found, without invoking unconventional gas relative permeabilities. A range of simulations was performed to assess the uncertainty in the inferred gas relative permeability and to highlight that in future experiments uncertainty can be reduced by performing a post-depressurisation waterflood to help quantify gas mobility. The new relative permeabilities are expected to lead to significantly higher predictions of gas recovery at the field scale.
A Dynamic Optimisation Technique for Simulation of Multi-Zone Intelligent Well Systems in a Reservoir Development
Authors: Arashi Ajayi , Konopczynski Michael
Published: December 2007

Intelligent well technology provides an operator the capability to remotely control, monitor and manage multiple horizons in a given well. Application of the technology has provided significant value, through the ability to control multiple zones independently, reduce total number of wells, reduce future costly well intervention, accelerate production between zones to maintain a plateau for extended period of time.

Common reservoir simulation tools are not well suited to model the performance of wells with downhole flow control devices, and specifically have difficulty automatically optimising the configuration of intelligent well control valves in the time domain, to maximise objective functions such as discounted production or hydrocarbon reserves recovered.

This paper reviews the process and results of reservoir simulation and modelling of a multi-layer, compartmentalized clastic oil reservoir with strong aquifer drive, developed using intelligent well technology. The paper describes the process by which an optimisation technique was incorporated in the simulator, with the ability to model binary and multi-position downhole intelligent well [L1]Interval Control Valves (ICVs).

The optimisation technique described was used to simulate the performance of a multi-layered commingled reservoir developed with intelligent wells. The production forecasts quantify the benefit of multi-position interval control valves over base case conventional development scenarios. For the typical reservoir studied, intelligent well systems accelerate production and maintain a longer plateau period when compared to conventional completion techniques.
Gas Holdup Imaging Identifies Complex Gas-Liquid Flow Regimes and Introduces a New Velocity Measurement in a Long, Cased Hole, Horizontal, Production Well
Authors: Whittaker Andrew Colin , Eriksen Synnøve Hjelmeland
Published: December 2007

Gas holdup probes run in a producing horizontal well on the Norwegian continental shelf are used to identify downhole flow regimes and compute the velocity of gas in intermittent flow.

The observed flow regimes are compared with the predictions of a number of gas-liquid flow correlations. The theory and quality of velocity correlations are discussed.
Quantifying the Value of Technical Work, Examples of Production Geophysics on the Brage Field
Authors: Robson Adrian , Hersvik Karl Jonny , Sperre Thomas
Published: December 2007

The Norwegian North Sea Brage field came on production in Sept. 1993. The field is currently producing approx. 6000Sm3/d and is on decline from its plateau rate of 19400Sm3/d. Drilling new production infill wells has increased production and has shown to be an effective way of prolonging the life of the Field. Learning from past well results has helped to improve methods. The main difficulty in this process is to accurately evaluate the success of well results. Statistics have been used to show trends and give an indication when variations occur. A detailed evaluation of well planning and well results was undertaken to demonstrate the value of specific geological and geophysical methods. Two examples from the Barge field are presented where the value of improved geophysical methods were estimated.
Safely Improving Production Performance through Improved Sand Management
Authors: Selfridge F. , Munday M. , Kvernvold O. , Gordon B.
Published: December 2007

Many operators implement a conservative approach to sand management implementing a "Zero Sand Production" or "Maximum Sand Free Rate" Criteria. This is due to the potentially severe consequences associated with sand production i.e. erosion, and the fact that existing standards and guidelines /1/ do not provide sufficient practical advice on how to manage erosion issues during operations. These criteria generally put restrictions on the production rate (and revenue) to reduce sand production and decrease the risk of erosion leading to a loss of containment. These restrictions are in many cases unnecessary.

This paper describes the development of an alternative approach which improves the production and safety performance of fields that are capacity restrained due to sand problems. The development of the approach started with a project for Conoco 1996 - 2000 /2/ and was further refined on a pilot project for Statoil in 2001 /3/, where it received the Statoil prize for the most successful R&D project in 2001.

From an erosion perspective the amount of sand produced is only one of many factors that must be managed; equally important factors are sand particle velocity, impact angle and material grading. By gaining a better understanding of the specific erosion characteristics of a field through: well sand risk ranking, identification of erosion critical components and detailed erosion assessment including 3D computer modeling; a more sophisticated erosion management strategy can be implemented identifying specific asset operational criteria, erosion monitoring and inspection requirements.

Implementation of this erosion management approach has provided operators with enhanced production, reduced inspection and maintenance costs without compromising safety and environmental targets and increasing/enhancing business performance.
Improving Understanding of the Potential for Enhanced Recovery from the UKCS
Authors: Kemp Alexander G. , Linda Stephen , Sola Kasim
Published: December 2007

The paper indicates expected production decline rates in UKCS under current expectations and gives the first systematic analysis of these. The paper then indicates that incremental investments in sanctioned fields have the potential to substantially modify these decline rates if adequate incentives are present.
Toward Zero Environmental Impact of the Produced Water
Authors: Knudsen B. L. , Hjelsvold M. , Frost T. K. , Eiken M. B. , Grini P. G. , Willumsen C. F. , Torvik H.
Published: December 2007

Reduced environmental impact is the goal when choosing produced water treatment technologies. On the Norwegian sector the method used for quantifying this impact is the Environmental Impact Factor, EIF. This method is computerized in a tool that calculates the environmental impact from each of a number of chemical component groups that are present in produced water.

Re-injection of produced water is the preferred option, and mostly used when pressure support is required. This paper, however, describes new treatment technologies aimed at produced water being released to sea. The technologies are suitable for different produced water compositions. The components in the produced water that contribute to the environmental impact are mainly: aliphatic hydrocarbons, heavy aromatic compounds (PAH), alkylated phenols and man added production chemicals. At several Statoil operated fields the corrosion inhibitor and H2S scavenger are giving a significant contribution.

Several new technologies will be described. Statoil has had a leading role and actively participated in the development and qualification of most of these technologies. The results from this work will be presented. The technologies will include the CTour process, Epcon CFU, droplet coalescing technologies as well as new technologies to reduce discharge of production chemicals.

The main conclusion is that knowledge is needed about which compounds contribute to the environmental impact of produced water before deciding which technology to use.
Parallel Reservoir Simulation Utilizing PC-Clusters in Massive Reservoir Simulation Models
Authors: Habiballah W. A. , Hayder M. E. , Khan M. S. , Issa K. M. , Zahrani S. H. , Shaikh R. A. , Uwaiyedh A. H. , Tyraskis T. P. , Baddourah M. A.
Published: December 2007

For the last five years parallel reservoir simulation has enjoyed great interest at Saudi Aramco. Realism in modeling the fields in Arabia requires the use of massive simulation models. These massive models capture detailed geological heterogeneity at relatively fine resolution. In addition, some of these fields have been producing for the last 50 years and are expected to continue to produce for decades to come. Today, there are more than 20 massive simulation models ranging in size from 500,000 to 10 million cells and are routinely used in managing the Saudi fields. Models of this magnitude require sufficiently "massive" computational power in order to carry out simulation studies in efficient and reasonable time. Faced with the challenge of meeting computational requirements, we were motivated to find a cost effective computational platform. In this work, we report on our experience in investigating PC-Clusters for mega-cell reservoir simulation studies. Our investigation demonstrated that commodity off-the-shelf Xeon based PC-Clusters can deliver an exceptional performance at minimal investment in computing hardware and software. Up to 9.6 million cells model running for 50 years have been tested. Currently Saudi Aramco uses PC-Clusters for its simulation work at not more than 15% of the cost of traditional solutions using supercomputers.
Investigation of New Tool to Unload Liquids from Stripper-Gas Wells
Authors: Ali Ahsan J. , Scott Stuart L. , Fehn Brad
Published: December 2007

Liquid loading in low production gas wells is a common problem faced in many producing regions around the world. The techniques available to remove liquids from the wellbore impose significant capital and operational costs. This study investigates a new method for unloading and restoring continuous production of low rate (stripper) gas wells. The performance of a patented vortex flow modifier tool was examined using a 125-ft vertical flow loop of 2-inch diameter clear PVC. The vortex device was found to alter the basic flow structure in the pipe resulting in improved liquid flow. The tool was observed to reduce tubing pressure loss by up to 17 precent and lower the minimum gas velocity required to lift liquids up the tubing string.
Pt. McIntyre: A Case Study of Gas Enrichment Above MME
Authors: Moulds T. P. , McGuire P. L. , Jerauld G. R. , Lee S-T. , Solano R.
Published: December 2007

This paper describes an evaluation to determine the optimum enrichment for an enriched gas drive project at the Pt. McIntyre field, Alaska. The miscible injectant (MI) at Pt. McIntyre displaces oil in a multi-contact miscible (MCM) displacement that is achieved through a combined condensing and vaporizing (C-V) mechanism. A range of MI compositions, varying from minimum miscible enrichment (MME) to substantially above MME, is available to the project.

Field-scale numerical simulation studies show that incremental oil recovery is nearly doubled when using the richest available MI composition. This is consistent with previously reported results for numerical simulation of field scale WAG processes that show significant improvement in recovery with continued enrichment. In this paper we further develop the mechanistic understanding of enrichment above MME on the recovery process.

Multiple contact mixing cell models show that continued enrichment above MME increases the effectiveness of both the condensing and vaporizing behaviors in the development of miscibility. In systems that are effectively non-dispersive, such as laboratory slimtube experiments, enrichment above MME has little impact on recovery. However, in field scale systems dispersion dominates MCM process efficiency, in this case enrichment above MME provides a powerful improvement in the MCM mechanism that substantially mitigates the deleterious effects of dispersion. We show how compositional core data from an MI swept interval provides insight to the recovery mechanism and confirmation of the impact of dispersion at field scale.

Previous studies into MI enrichment have reported that for a four-component system the mechanism changes from C-V to purely condensing as the enrichment level approaches first contact miscibility (FCM). We show that with the addition of a small amount of heavy component the C-V behavior is retained with increasing enrichment until transition into FCM. This makes it unlikely that a transition to purely condensing mechanism will occur in real reservoirs.

The impact of gas-oil relative permeability dependence on IFT was assessed. It is found that relative permeability modification is of secondary importance compared to the recovery benefits due to enhanced compositional performance using richer MI.
Case Studies of Uncertainty Analysis in the Seismic to Reservoir Simulation Workflow
Authors: Sahni Akshay
Published: December 2007

This paper presents the work of a multidisciplinary team of earth scientists and engineers to develop an offshore heavy oil field while accounting for uncertainties in the geological and reservoir simulation models. The field is located in shallow waters and has oil ranging in viscosities from 20cp to 200cp. The depositional environment is a fluvial meandering river system where the sands are thin and disconnected. The field has a handful of appraisal wells and 3-D seismic data, along with extensive measurements of rock-fluid properties and geochemistry analysis. Some of the appraisal wells also have good quality DST and MDT data which was used to constrain the geological model.

The workflow comprised of constructing a geological model using deterministic geo-bodies identified from analysis of acoustic impedance and stochastic sands in areas of poor seismic quality or below the threshold of seismic resolution. These stochastic sands were tied to well control and simulated using a sequential indicator technique. Various field development scenarios were considered, including inverted five spot and nine-spot pattern waterfloods, along with application of horizontal wells. Development scenarios and predictions incorporated uncertainties in water oil contact's, net-to-gross, oil viscosities, relative permeability, residual oil saturations, injectivity and skin factors. The use of experimental design techniques and parallel simulation enabled the team to capture the range of uncertainty in subsurface and engineering parameters while keeping computational times manageable. The paper discusses some of the key uncertainties and challenges in bringing this and similar reservoirs to development.
Subsurface Uncertainty Management in the Harweel Cluster, South Oman
Authors: O'Dell Mike , Lamers Edwin
Published: December 2007

There has been a string of exploration successes the past five years in discovering some 350 million m3 (2 billion barrels) of oil in the Harweel Cluster in South Oman. This oil is deep, at high pressure, comes with high GOR, and the fluids contain 15% CO2 and 5% H2S. Of the nine Precambrian carbonate reservoirs, six are lithostatically pressured and three are hydrostatic. The Harweel Cluster is more than 70 km from existing infrastructure. If gas can be re-injected, miscible displacement is expected in many of the reservoirs. The Harweel Cluster is one of Oman's major opportunities for "green field" oil development.

There is a large degree of subsurface uncertainty in gross rock volume and Oil-Water-Contact, reservoir architecture, faults and fractures and reservoir compartmentalization, degree of dolomitization, permeability level and heterogeneity, fluid properties, and so on. However, little is known about the scale and relative importance of each of these uncertainties. Some uncertainties, such as compositional grading, might turn out to be more important than anticipated when evaluating development options due to non-linearities and dependencies.

Analyzing the effects of all uncertainty combinations in all reservoirs is not a realistic option. Therefore a structured scenario based approach has been developed to analyze and assess all potential factors influencing recovery schemes, reserves and productivity. After evaluating the range of possible values and calculating the impact of each uncertainty, realizations were created to represent the range of possible values in each new reservoir. Field scale equation-of-state models were used to simulate both primary depletion and gas re-injection. Development scenarios were optimised for each discrete realization. The resulting reservoir models serve as a basis for the development concept selection and the subsequent Field Development Plans.
Evaluating Well Performance and Completion Effectiveness in Hydraulically Fractured Low-Permeability Gas Wells
Authors: Cramer David D
Published: December 2007

Hydraulic fracture stimulation often dictates the economic outcome of wells completed in low permeability gas reservoirs. Attempting to understand well performance - the rate and pressure behavior of a well over its productive life - provides the opportunity to discover the elements driving stimulation and completion effectiveness. This paper demonstrates the integrated use of practical reservoir engineering methods to evaluate well performance, identify flow regimes and distinguish between reservoir and completion induced behavior in low-permeability hydraulically fractured gas wells.
Clean-up of Water Blocks in Low Permeability Formations
Authors: Mahadevan Jagannathan , Sharma Mukul M.
Published: December 2007

Water-blocked low permeability gas formations with drawdown pressures comparable to capillary entry pressures can take a very long time to clean up. The clean up of water blocks in gas wells occurs in two regimes: displacement of the fluids from the formation followed by vaporization by the flowing gas, which becomes under-saturated as the pressure decreases.

This work aims to study the effect of rock permeability, wettability, temperature, drawdown and surfactants on the clean up of cores containing brine. The effectiveness of using solvents for cleanup under different conditions has been evaluated by comparing gas relative permeabilities with and without methanol.

Gas displacement experiments were conducted on cores fully saturated with brine. The gas relative permeability increases with pore volumes of gas injected for long periods of time (up to 100,000 PV) at ambient temperature. The addition of methanol, increasing temperature and increasing core permeability resulted in faster cleanup after about 50 to 100 PV of gas flow. The change of wettability of the rock from water-wet to oil-wet also resulted in faster recoveries in gas relative permeability.

Our observations show that the clean up of water-blocks can be improved by: 1. Influencing the displacement of brine, i.e. by changing the wettability and, 2. By increasing the rate of vaporization by introducing volatile solvents such as methanol. It is found that changing wettability also has an impact on the rate of vaporization of the brine and methanol.

The study quantifies the effects of factors such as rock permeability, wettability, surface tension, and temperature on gas relative permeability. The results of this study will help in selecting strategies for clean-up of water blocks created due to various operations such as drilling, acidizing and fracturing, and making recommendations for the use of surfactants or solvents for well treatments to remove water blocks.
Optimal Appraisal Well Location Through Efficient Uncertainty Reduction and Value of Information Techniques
Authors: Haskett William J.
Published: December 2007

Successful exploration, efficient appraisal, and profitable extraction are the three phases of any E&P project; each in turn is dependent upon the prior. However, efficient appraisal of newly discovered resources sets the stage for maximizing project profitability and managing risk. The goal of an efficient appraisal program is to achieve maximum reduction in uncertainty with minimal cost. The more certain a company is regarding the size and scope of a particular project, the better decision it can make on its development case selection, the greater the possibilities for downside risk mitigation, and the more efficiently it can manage its entire development portfolio. The end of the appraisal period occurs when further uncertainty reduction would not materially effect the principle development decisions, or at the point at which the downside project risk becomes acceptable to the company.

Specific appraisal locations should typically be selected on their ability to provide the greatest overall reduction in project uncertainty. Project uncertainty is tied directly to the variance of the outcome distribution and can be summarized by the uncertainty range, which utilizes the commonly understood distribution descriptors. An understanding of the difference between discrete learning events and population sampling learning is critical to the estimation of uncertainty reduction.

Potential appraisal locations will contribute to a reduction in uncertainty given either failure or success. Competing appraisal locations may be compared through their propensity for uncertainty reduction using standard value of information techniques (VoI). This quantitative method provides an assessment of the relative value of uncertainty reduction of competing or prioritized development locations, and may be extended within a multi-prospect situation to rank competing prospects within a commonly constrained business opportunity.
Measurement of the Two-Phase Gas Slippage Phenomenon and Its Effect on Gas Relative Permeability in Tight Gas Sands
Authors: Rushing J. A. , Newsham K. E. , Van Fraassen K. C.
Published: December 2007

This paper presents results from a laboratory study of the two-phase gas slippage phenomenon and its impact on effective and relative gas permeabilities in tight gas sands. Core samples from the Bossier tight gas sand play in the Mimms Creek Field in Freestone Co., TX were evaluated at water saturations ranging from 5 to 40 percent. We also investigated the effects of net overburden pressure and reservoir temperature on this phenomenon. Results from our study indicate that, if two-phase gas slippage is not considered in the laboratory measurements, then we may overestimate gas relative permeabilities.
Disaster Insurance Using Portfolio Management Techniques
Authors: DuBois James R. , Quarles Andrew I.
Published: December 2007

There is a growing body of literature in our industry that addresses the use of portfolio management techniques to find "optimum" mixes of projects that meet company goals while managing risk. These investigations usually start by describing "risk" in some manner, then proceed to illustrate how combinations of properties can be chosen that minimize this risk function subject to the other goals of the company. The probabilities of meeting individual metric targets in discrete time frames can and should also be quantified.

This type of analysis is valid and useful, and forms the backbone of project portfolio management. However, when dealing with risk and probability concepts it is easy to lose sight that specific events will occur in time, and that the portfolio must include enough flexibility to allow reaction to and recovery from these events.

Specifically, acceptable portfolio results may depend on a small number of projects performing at a certain level. Because the chance of these important projects not performing at this level may be relatively small, the risk is deemed "acceptable". If one of the projects subsequently fails to perform, what was once "acceptable risk" can become an exercise in salvaging a year or even saving a company.

In this paper, we will show how portfolio management techniques can be used to plan a portfolio robust enough to recover from a potential future disaster. We will demonstrate with examples how the techniques can lead us to make investment choices today that might not be obvious if projects are evaluated solely using their expected values. These choices, if made judiciously, can provide insurance against possible future downside.

Portfolio analysis is a powerful technique, with applications far beyond the standard risk-reward exercise. We will show here some examples of how it can be used to provide insight into the practical business questions that truly concern company management.
Petroleum Engineering Education and Training Initiatives across Asia Pacific
Authors: Lloyd P. M. , Ronalds B. F.
Published: December 2007

The paper summarizes the discussion and key outcomes of the Asia Pacific Colloquium on Education and Training for the Petroleum Industry, held in Bali in September 2002. This Colloquium was a little different from the two previous events in this series because it not only tried to define the skill sets of the engineers whom the industry would like to see graduate, but it also looked at keeping skill sets current during their careers.

We believe that the three Asia Pacific Petroleum Engineering Colloquia over the past six years have played a pivotal role in bringing industry and educators together to debate and reach consensus on future education and training needs. The fruits of these labors were evident in this third colloquium. However, "engineering certification" is an issue which we anticipate will become increasingly important in the region in the next few years, and effort should be put in this area so that the professional societies can have ownership.
Building Reservoir Models Based on 4D Seismic & Well Data in Gulf of Mexico Oil Fields
Authors: Bogan Catherine , Johnson Daniel , Litvak Michael , Stauber Doug
Published: December 2007

A general methodology has been developed for building and history matching reservoir models based on 4D seismic, petrophysical, and production data. The methodology consists of: construction of structural maps of different reservoir zones; building 3D facies models; geostatistical construction of 3D volumes of reservoir properties (porosity, net-to-gross ratio, permeability) constrained by seismic and well log data; construction of fluid flow barriers; and matching of seismic attribute changes over time.

A procedure has been developed for building confining surfaces of the reservoir zones matching well markers and velocity maps. Object based modeling tools have been applied for the construction of the 3D facies models constrained by seismic and well data, and consistent with depositional environment. The construction of the 3-D volumes of the reservoir properties is based on latest achievements in rock mechanics - sim2seis correlations, which correlate seismic attributes (for example, acoustic impedance AI) to porosity, net-to-gross ratio, pressure, water & gas saturation and rock properties. The procedure has been developed to calibrate sim2seis correlations based on well log and pressure data. The procedure is applied for effective porosity definition, in two parts. First, correlating 3D seismic AI with well logs averaged over the corresponding model cells derives an effective porosity trend. Second, geostatistical modeling tools are applied to define the 3D effective porosity volume constrained by well log data and the effective porosity trend. A new procedure has been developed for the construction of the fluid flow barriers from 4D seismic.

The developed methodology has been applied in several Gulf of Mexico oil fields. It has been demonstrated that: a reasonable history match can be achieved without any adjustments of the reservoir models, and that fluid flow barriers derived from 4D seismic significantly improve history matching results. A good match of predicted results and field measurements from recently drilled wells (suggested by reservoir modeling) has demonstrated the prediction capabilities of the constructed reservoir models.
The Role of Cut-offs in Integrated Reservoir Studies
Authors: Worthington Paul F. , Cosentino Luca
Published: December 2007

There have been many different approaches to quantifying cut-offs, with no single method emerging as the definitive basis for delineating net pay. Yet, each of these approaches yields a different reservoir model, so it is imperative that cutoffs be fit-for-purpose, i.e. they are compatible with the reservoir mechanism and with a systematic methodology for the evaluation of hydrocarbons in place and for the estimation of reserves. These different requirements are accommodated by basing the quantification of cut-offs on reservoir-specific criteria that govern the storage and flow of hydrocarbons. In so doing, particular attention is paid to the relationships between the identification of cut-offs and key elements of the contemporary systemic practice of integrated reservoir studies. The outcome is a structured approach to the use of cut-offs in the estimation of reserves. The principal benefits of a properly conditioned set of petrophysical cut-offs are a more exact characterization of the reservoir with a better synergy between the static and dynamic reservoir models, so that an energy company can more fully realize the asset value.
Integrated Fractured Reservoir Characterization and Simulation: Application to Sidi El Kilani Field, Tunisia
Authors: Laribi M. , Boubaker H. , Beck B. J. , Chen H-K. , Amiri-Garroussi K. , Rassas S. , Rourou A. , Boufares T. , Douik H. , Saidi N. , Ouenes A.
Published: December 2007

Sidi El Kilani field produces oil from a Type 1 fractured carbonate reservoir. The field has produced 42 mmstb oil since first production in 1991, and has consistently out-performed expectations. As with many fractured reservoirs it has proved difficult to describe and model the fracture distribution or to predict or control water breakthrough. Prior to this study three out of nine boreholes in the field encountered tight rock and are dry holes.

This integrated study used geophysical, geologic, and engineering data simultaneously to improve the reservoir description. The reservoir model was proven with the successful completion of a 400m horizontal sidetrack of one of the dry holes. The successful characterization of the fractures was mostly due to the extensive use of 3D seismic data. Seismic impedance, velocity, density and coherence were used as input in the integrated fracture modeling process. Seismic data was also used to derive geologic drivers. In all nineteen geologic and seismic drivers were correlated, using artificial intelligence tools, against a fracture porosity indicator computed from conventional logs. 3D permeability models were then derived using a whole core porosity-permeability relationship, and input into a reservoir simulator. The production history of most wells was readily matched.

The drilling results indicate that the 3D fracture models can be used successfully to locate highly fractured areas. This was possible by using an integrated fracture modeling approach. None of the individual geologic and geophysical drivers gave a clear and accurate description of the 3D distribution of the fractures. Their simultaneous use with a fracture porosity indicator and artificial intelligence tools revealed the complexity of the reservoir and its fracture network.
Integrating Short-Term Pressure Buildup Testing and Long-Term Production Data Analysis to Evaluate Hydraulically-Fractured Gas Well Performance
Authors: Rushing J. A. , Blasingame T. A.
Published: December 2007

This paper presents an integrated approach for evaluating the post-fracture performance of gas wells completed in tight gas sands. Our technique focuses on a methodology for evaluating the stimulation effectiveness of hydraulically fractured gas wells. Rather than relying on a single evaluation technique, we integrate short-term pressure buildup testing with long-term production data analysis using decline type curves. We illustrate the applicability and efficacy of our technique with examples from more than twenty wells completed in tight gas sands. The results of our paper also demonstrate the value and function of short-term pressure buildup tests performed in tight gas sands.
Hydraulic Fracture Mapping of the High-Temperature, High-Pressure Bossier Sands in East Texas
Authors: Griffin L. G. , Sullivan R. B. , Wolhart S. L. , Waltman C. K. , Wright C. A. , Weijers L. , Warpinski N. R.
Published: December 2007

Anadarko Petroleum Corporation has conducted a study to improve hydraulic fracturing and field development in the Bossier sands in the East Texas Basin. As part of this study, hydraulic fracture mapping was performed with microseismic imaging on three wells completed in the Bossier sands.

Microseismic fracture mapping is an emerging technology to optimize development of hydraulically fractured reservoirs. This paper demonstrates the use of microseismic mapping under high temperature (300°F) conditions. It also demonstrates how the directly measured results can be implemented to calibrate a 3D fracture growth model.

The study shows mapping results for waterfracs and hybrid fracture treatments (which utilize slickwater to generate the fracture geometry and crosslinked gel to transport the proppant) in the Bossier. Fracture azimuth was fairly consistent for the three wells and fit with earlier surface tiltmeter mapping result in this area. Fracture growth asymmetry was observed and is discussed in the paper. Payzone coverage was generally good but could be improved and created fracture lengths varied significantly between wells.
Drawdown Guidelines for Sand Control Completions
Authors: Tiffin David L. , Stein Michael H. , Wang Xiuli
Published: December 2007

This paper details a method for determining maximum safe production rates for sand control wells. This method was developed from a thorough compilation of data from over 200 sand control wells. As a result of this analysis, a simple function of flux (fluid flow per unit area of screen) proved very reliable at separating wells operating safely from those resulting in damaged screens or unacceptable amounts of produced sand.

Prior to this work, BP (and the industry) used a variety of methods to attempt to optimize production from sand control wells. Most of these prior methods use pressure drop across the completion and were loosely based on experience and rules of thumb. It is shown that these pressure based draw down limits are either ineffective for managing risk of well integrity or unnecessarily constrain well productivity.

We are currently using this new flux-based approach as a basis of design for new wells and to open existing wells to a maximum safe operating production rate. Significant production addition has been added without any well failures as a result of opening up these artificially constrained wells. We furthermore anticipate preventing future well failures caused by operating at too high a rate. Earlier in 2002, two BP-operated sand control wells suffered apparent screen erosion failures; both operating at low drawdowns and safe limits using old guidelines, but at flux rates exceeding these new proposed guidelines.
Use of High-Strength Alloys and Elastomers in Heavy Completion Brines
Authors: Silverman Seth A. , Bhavsar Rashmi , Edwards Charles , Virally Stephane , Foxenberg William
Published: December 2007

Recent field experiences have shown that stress corrosion cracking (SCC) failures can occur when high-strength, low-alloy steels and stainless steels are exposed to heavy completion brines. SCC of super 13Cr and duplex stainless steels has also been reported in lighter CaCl2 brines that have sulfur-containing additives. Modifications of fluid composition with particular attention to additive selection and careful materials selection are required to prevent field failures of completion and service-tool hardware.

The authors have performed laboratory testing to understand the interactions of completion brines that contain zinc bromide (ZnBr2) with the common metallurgical alloys used in service tools, workstring materials, and other permanent downhole equipment. There has been little published work on environmental cracking of common engineering alloys in corrosive ZnBr2 blends. Recent case histories with high-strength downhole service-tool components are described and solutions are proposed to address exposures to heavy brines. Selection of elastomers and seals for use in these environments also requires consideration of the fluid type and additive package.

As a result of their testing, the authors have developed internal guidelines that require the use of severe service equipment for brines with densities higher than 17.0 lbm/gal in temperatures over 275ºF. If thiocyanate additives are required for corrosion control, careful control of the brine blend, pH modification, and/or the use of organic sulfide scavengers are recommended.
Acid Fracturing HT/HP Gas Wells Using a Novel Surfactant Based Fluid System
Authors: Nasr-El-Din Hisham A. , Al-Driweesh Saad , Al-Muntasheri Ghaithan A. , Marcinew Richard , Daniels John , Samuel Mathew
Published: December 2007

During acid fracturing of carbonate reservoirs, the acid dissolves the rock, creating wormholes which increase fluid loss. Excessive fluid loss lowers the net pressure in the fracture limiting fracture extension, and adversely affects the conductivity of the fracture. To overcome this problem, multiple stages of polymer pads are usually pumped in acid fracturing treatments to reduce leak-off. In addition, synthetic polymers are commonly added to the acid to produce gelled or in-situ gelled acids. The objective of adding these polymers is to reduce leak-off, by increasing the viscosity of the acid. This in turn reduces the rate of mass transfer of the acid to the rock surface. However, several studies have shown that these polymers can cause formation damage. Moreover, the cross-linker can precipitate in the formation causing further damage. Efficient mixing of synthetic polymers in the field is also a concern, especially when the polymers are present in a solid form.

To overcome problems associated with polymeric fluids, polymer-free fluids were used for the first time to acid fracture several vertical wells in a deep gas reservoir in Saudi Arabia. The acid fracture treatments consisted of several stages including: viscous pads, emulsified acid, in-situ acid and an inhibited acid. A visco-elastic surfactant system replaced the polymers used in the pad and the leak-off control acid (28 wt% HCl). Calcium chloride produced from acid reactions with the carbonate rock viscosifies the acid in-situ, reducing leak-off volume.
Simulation of Collapse Loads on Cemented Casing Using Finite Element Analysis
Authors: Rodriguez W. J. , Fleckenstein W. W. , Eustes A. W.
Published: December 2007

Collapse phenomenon behavior has been broadly studied in the petroleum industry but few changes have been implemented in this subject. Since the early 1960's when the American Petroleum Institute (API) published the Recommended Practice 5C3 for casing design equations under burst, collapse and tension, these equations have remained unchanged until the present.

These equations ignore the effects of the cement sheath on collapse resistance and assume uniform collapse loading of the casing. Incorporating the effects of a cemented wellbore improves collapse casing design. The study presented in this paper describes the effects on the collapse loading conditions of the mechanical properties of cement and rock formation surrounding the casing strings. In order to investigate these effects, the Finite Element Analysis technique was used. Three separate cases are studied: unsupported casing; casing with a cement sheath bonded outside of it; and casing, cement sheath, and consideration of the surrounded rock formation. For all of them, the same constant value of stress was applied at the outer boundary of each model. According to the results yielded by this study, improvements of up to 62% in casing collapse resistance can be achieved, depending on the mechanical properties of the cement systems and rock formation properties.
Imaging the Initiation of Asymmetrical Hydraulic Fractures in Laboratory Experiments
Authors: Zeng Zhengwen , Roegiers Jean-Claude , Grigg Reid
Published: December 2007

Asymmetrical hydraulic fractures have been observed in the field to reduce the efficiency of such stimulation treatments. Efforts have been made to investigate asymmetrical hydraulic fractures by imaging their initiation using microseismic imaging technology developed in-house. Images of the fracture initiation were generated using the located sources of microseismic events. Analyses of these images indicate that the initiation of an asymmetrical hydraulic fracture is a complex process. While asymmetrical fractures were generated under asymmetrical stress fields along the length direction, selective propagation along the height direction was also observed, as well as nonalignment and reorientation of the fractures near the borehole. Scarce distribution of microseismic events near the borehole may indicate poor connection between the far-field fracture and the borehole. Dense distribution of microseismic events near the borehole probably results from the coupled effect of fluid leakoff and stress-induced tensile fracturing.
The Study of a New Overall Hydraulic Fracturing Mode in Low Permeable and Unconventional Reservoirs
Authors: Jiang Tingxue , Wang Yongli , Ding Yunhong , Shan Wenwen , Wang Xin , Zhou Xiangguang , Liu Jixia
Published: December 2007

A new fracturing mode is put forward in the paper. Compared with the former mode, the new one has the following advancements: 1) Some key reservoir parameters such as effective permeability, effective thickness, loss coefficient, fracture azimuth and fracture height as well are all regarded as stochastic variables according to field statistic results; 2) Fracture length and conductivity are accordingly stochastic variables as a result of the random distribution of such fracturing treatment parameters as pumping rate, sand to liquid ratio, pad volume and sand volume as well; 3) As a result of undetermined reservoir and fracture variables, the post-fracturing rate is stochastic in most cases; 4) Monte Carlo method is utilized to perform economic analysis, and the relationship of net present value versus probability in a certain unconventional reservoir may be available on the base of above works, so that a decision-making policy may be determined accordingly. After that, one field case is hydraulically fractured utilizing above strategy, and the post-fracturing effect is very satisfied, which indicates that the new overall hydraulic fracturing mode put forward in the paper is reliable and if it is put in to field applications, a greater economic benefits may be expected.