bluuebunny/crossref_metadata_2025 huggingface dataset:
Three-Dimensional Modeling of the Evaporation of Volatile Hydrocarbons from Heterogeneous Porous Media
Authors: Yiotis A. G. , Tsimpanogiannis I. N. , Stubos A. K. , Yortsos Y. C.
Published: December 2007

Lean gas injection has been considered as a process to improve the recovery of bypassed volatile oils from the matrix of fractured reservoirs. The characterization of flow and mass transfer in fractured reservoirs is a challenging task, due to the complexity of the pore space, the heterogeneity in the permeability of the rock, as well as the complex interplay between capillary, viscous and buoyancy forces. In the present paper we study the effect of heterogeneity. We develop a three-dimensional pore-network simulator that accounts for evaporation and diffusion of the volatile liquid trapped in heterogeneous pore networks. A series of numerical simulations are performed in common types of natural porous media.

We investigate the effect of permeability gradients on the saturation profile, the recovery rates of the trapped liquid clusters, the evaporation patterns and the stability of the receding evaporation front. The case of a negative permeability gradient (high permeability close to the fracture, low permeability far away) leads to a stable evaporation front. Conversely, the effect of positive permeability gradients (low permeability close to the fracture, higher permeability far away) leads to a fingered pattern, that results in lower recovery times due to higher liquid saturation at the product surface. The paper finds application to problems of evaporation or drying of volatile liquids or other liquids from porous media. These arise in enhanced oil recovery in fractured systems, as well as in the remediation of contaminated soils.
Alternative Approaches to Real Option Valuation: A Critical Appraisal
Authors: Wilkinson D. , Bailey W. J. , Couët B.
Published: December 2007

Recent years have seen numerous management and petroleum-related articles on the application of financial option techniques to valuation of real assets under uncertainty and operational flexibility. However, universal acceptance of this methodology has been elusive or even resisted. Such reluctance is understandable, as many inconsistencies exist in the various methodologies. Part of the problem is that, although each proposed method provides an answer (the calculated value), the precise meaning of this value is unclear. In this work, we suggest an operational definition of the real option price, and a criterion for deciding whether a given method generates an answer that agrees with this definition. We then consider two real option methodologies: multi-lattice and consolidated. The former retains the fundamental degrees of freedom of the problem, while the latter combines all uncertainties into a single effective volatility. The methods are analyzed in terms of a simple oilfield salvage option. It is observed that part of the discrepancy between the methods is caused by a general difference in valuation techniques, one that is not specific to the optionality of the problem. When the consolidated method is revised so that the two methods give the same value of the project in the absence of optionality, the option values are in reasonable agreement with each other.
Effect of Downhole Pressure Conditions on High-Power Laser Perforation
Authors: Gahan B. C. , Batarseh S. , Watson R. , Deeg W.
Published: December 2007

Researchers at Gas Technology Institute (GTI) have been exploring the use of high power laser energy as a non-damaging alternative to conventional explosive perforation methods. All previous laser/rock interaction tests were performed on samples in the lab at atmospheric pressure. To determine the effect of downhole pressure conditions, a sophisticated tri-axial cell was designed and tested. For the first time, Berea sandstone, limestone and clad core samples were lased under various combinations of confining, axial and pore pressures. Clad core samples consisted of steel cemented to rock in an effort to represent material penetrated in a cased hole. The results of this experiment will assist in the development of a downhole laser perforation prototype tool.

In the past, several combinations of laser and rock variables were investigated at standard conditions and reported in the literature. More recent experiments determined the technical feasibility of laser perforation with a 5.34 kW Ytterbium-doped multiclad fiber laser exposed to multiple samples of rock, cement and steel. The fiber laser was capable of penetrating these materials under a variety of conditions, to an appropriate depth, and with reasonable energy requirements. It was determined that fiber lasers are capable of cutting rock without causing damage to flow properties. Furthermore, the laser perforation resulted in permeability improvements on the exposed rock surface.

This paper will discuss the design and development of a customized laser pressure cell; experimental design and procedures, and the resulting data on pressure-charged samples exposed to the laser beam. An analysis will provide the resulting effect of downhole pressure conditions on the laser/rock interaction process.
Fundamental PVT Calculations for Associated and Gas/Condensate Natural Gas Systems
Authors: Sutton R. P.
Published: December 2007

Problems with existing procedures used to estimate gas PVT properties are identified. The situation is reviewed and methods proposed to alleviate these problems. Natural gases are derived from two basic sources - associated gas which is liberated from oil and gas condensates where hydrocarbon liquid, if present, is vaporized in the gas phase. The two gases are fundamentally different in that a high gravity associated gas is typically rich in ethane through pentane while gas condensates are rich in heptanes-plus. Additionally either type of gas may contain nonhydrocarbon impurities such as hydrogen sulfide, carbon dioxide and nitrogen. Failure to properly distinguish between the two types of gases can result in calculation errors in excess of those allowable for technical work. Sutton investigated high gravity gas condensate gases in 1985 and developed methods for estimating pseudocritical properties which resulted in more accurate Z factors. The method is suitable for all light natural gases and gas condensate gases. It should not be used for high gravity hydrocarbon gases that do not contain significant levels of heptanes-plus. The original Sutton database of gas condensate PVT properties has been expanded to 2264 gas compositions with over 10,000 gas compressibility factor measurements. A database of associated gas compositions containing over 3200 compositions has been created to evaluate suitable methods for estimating PVT properties for this category of gas. Pure component data for methane, methane-propane, methane-n-butane, methane-n-decane and methane-propane- n-decane has been compiled to determine the suitability of the derived methods. The Wichert55 database of sour gas compressibility factors has been supplemented with additional field and pure component data to investigate suitable adjustments to pseudo-critical properties that ensure accurate estimates of compressibility factors. Mathematical representations of compressibility factor charts commonly used by the engineering community and methods used by the geophysics community are investigated. Generally these methods are robust and have been found suitable for ranges beyond those originally recommended. Natural gas viscosity, typically estimated through correlation, has been found to be inadequate for high gravity gas condensates requiring revised procedures for accurate calculations.
Combined Seismic and Production History Matching
Authors: Khazanehdari J. , Curtis T. , Yi T.
Published: December 2007

Production history matching in isolation can result in several nonunique realizations of reservoir parameters; using this practice only modifies the reservoir in the drainage region of the measurement wells. In early production and in fields with a low density of producing-well coverage, production history matching is particularly erroneous. By constraining the production history matching with time-lapse seismic data, a faster convergence to a better solution with reduced uncertainty can be achieved. The repeat acquisition of three-dimensional (3D) seismic data, commonly known as "time-lapse" seismic reservoir monitoring or four-dimensional (4D) data acquisition, is based on the fact that reservoir production and injection significantly change the reservoir's fluid saturation, pressure, and temperature. This subsequently alters the acoustic response of the reservoir rock that can be detected using the seismic method.

Combined seismic and production history matching was conducted on a small segment of a reservoir model from a North Sea hydrocarbon field, using software which could simulate changes in the reservoir. The selected segment for modeling consisted of a producing well and an injector well. The existence of several repeated 3D high-resolution seismic datasets provided a unique opportunity to carry out a combined time-lapse and production history matching. A quantitative 4D fluid saturation and pressure mapping technique allowed calibration of 4D seismic responses coupled with flow simulator models.

The modeled results, using production history matching alone, were poor, predicting low water cut, where in fact, the water cut was as high as 60%. The combination of seismic data and production history matching resulted in a better prediction and quicker convergence to a solution that more closely matched both the calibrated seismic and the production data.

The successful results from the integrated and quantitative approach described in this paper demonstrate a potential for the future integration of seismic and reservoir data to deliver improved reservoir production and reservoir management.
Predicting Openhole Horizontal Completion Success on the North Slope of Alaska
Authors: Erwin M. D. , Ogbe D. O.
Published: December 2007

The Colville River Field (Alpine) represents the first widespread and successful application of openhole horizontal completions on the North Slope of Alaska, and one of the first in the world. The purpose of this paper is to examine why this completion technique was selected and identify the key parameters that favored its successful application in the Colville River Field. The optimal completion technique for a candidate well is determined by the reservoir properties, geologic setting, rock mechanics, development plan and completion design. In this paper we will review the unique advantages and disadvantages of openhole horizontal completions based on the Colville River Field.

From the results of the review, three key parameters were found to be critical to the success of openhole horizontal well completions and should be applied broadly in other situations. Using these three key parameters as criteria, other major North Slope reservoirs are evaluated to determine their potential for openhole horizontal completion applications. Focus areas in this evaluation include in-situ reservoir parameters, development plans, fluid contacts, and wellbore geometries. The results showed that only one other major field on the North Slope could have benefited from openhole completions.

The results of this paper are meant to provide guidelines for the future application of openhole horizontal completions both on the North Slope of Alaska and beyond.
Proppant Flowback Prevention—A New Technology for Low BHST Applications
Authors: Johnson D. E. , McWilliams J. L. , Nelson S. G. , Blount J. S.
Published: December 2007

A new phenolic resin system has been developed for proppant consolidation when fracturing low temperature wells. Before the development of this new resin system, which was in response to a global industry need, external chemical activators were necessary to achieve sufficient bond strength of the resin coated sand pack (when treating wells with bottom-hole temperatures less than 140°F). This new low-temperature cure system develops superior proppant pack bond strength and requires no external activation at temperatures as low as 100°F. Eliminating the need for external activators not only decreases the complexity of the fracturing treatment, but also contributes to the saving of time, money, and decreases the need for chemical transportation and the associated potential hazards. However, the lower operating temperature limit of this resin chemistry can be extended even further with the addition of an external chemical activator.

The paper will discuss product performance data that was generated to document the effectiveness of this technology at simulated downhole conditions. Results from the initial field trials utilizing the new Low Temperature Resin Coated Curable Proppant (LTRCCP) in various shallow wells in the Permian Basin will also be presented. Field trial data resulted from thirty-nine treatments that were performed on a total of twenty-two wells, in nine different producing horizons, spread over four different fields in Southeast New Mexico and West Texas. The Information presented describes formation properties, treatment designs, post fracturing production response and lessons learned.
A Neurosimulation Tool for Predicting Performance in Enhanced Coalbed Methane and CO2 Sequestration Projects
Authors: Gorucu F. B. , Ertekin T. , Bromhal G. S. , Smith D. H. , Sams W. N. , Jikich S. A.
Published: December 2007

One of the more important environmental issues is the increase in atmospheric carbon dioxide (CO2) concentration resulting from anthropogenic sources. The CO2 sequestration process includes capturing, separation and storage of carbon dioxide, and targets a potential solution mitigating the amount of CO2 in the atmosphere. This work focuses on the last component of the aforementioned sequestration process, storage of CO2. Coal seams are chosen as potential repositories because there are several advantages where the sequestration costs can be offset in various ways.

The purpose of this study is to develop a tool for the practicing engineer to predict the important performance indicators that are critical in CO2 storage projects in coal seams. The neuro-simulation methodology coupling the hard computing protocols with the soft computing protocols is used. PSU-COALCOMP, a compositional coalbed methane reservoir simulator (hard computing protocol), is used to generate the necessary training data sets utilized in the training of the artificial neural networks (soft computing protocol) that are developed in this study. The tested neural network predictions are found to be accurate and sufficiently precise to establish confidence in the tool. Accordingly, the developed neural network can be used to screen thousands of possible scenarios of operational conditions in the optimization of the coal sequestration project design parameters in few seconds without going through intensive numerical simulations.
Multidimensional Velocity-Based Model of Formation Permeability Damage: Validation, Damage Characterization, and Field Application
Authors: Mojarad R. S. , Settari A.
Published: December 2007

The loss of injectivity in produced water and seawater injectors due to formation plugging is well documented in the literature. Reliable modeling of the permeability loss is the key to the analysis of field data and to design and economics of projects.

Standard formulation of damage mechanics is based on the classical deep bed filtration (concentration-based) model, which requires two parameters: filtration coefficient λ and formation damage coefficient β. Determinationof these paramteters is expensive and difficult. Moreover, the model is not easily implemented in reservoir simulators.

This paper presents an alternative approach to modeling damage based on the formulation proposed by Bachman et al. (SPE 79695). The numerical implementation and validation of this empirical, velocity-based model is extended to two dimensions. The model was extended to 2-D flow and validated by a comparison with the deep bed filtration model. The velocity model gives remarkably accurate approximation to the more complex concentration model. Unique relation between the parameters of the two models was found, and used to develop a new methodology to characterize damage by matching lab or field data.

Application of the model to the published data from offshore Gulf of Mexico is presented. The velocity method allows more accurate history matching and the damage characterization by history matching yields parameters close to those measured.
Openhole vs. Cased-Hole Hydraulic Fracturing
Authors: Gottschling J. C.
Published: December 2007

Proposal

An open-hole hydraulic fracturing (OHF) process has evolved to economically treat low pressure and low quality upper Devonian sands in western Pennsylvania.

In order to evaluate the effectiveness of the OHF process, a study was done to chronicle, investigate and postulate about the OHF process. This study used well data from two particular fields in western Pennsylvania. Data from Field #1 was used to provide OHF and offsetting cased-hole production data. Field #2 was the source for all mini frac analyses plus additional producion data. The study focus involved several integral parts.

Understanding of the geology typical to the areas where the OHF process was common was accomplished by referencing the ample amount of published data on the upper Devonian sands in western Pennsylvania. Additional information was incorporated from recent core studies.

Creating a chronicle of the OHF process involved a detailed step-by-step description of the process along with pressure analyses to determine created fracture geometry and reservoir permeability. Breakdown data from 160 OHF stages was analyzed in an attempt to predict the production potential of a zone.

The final segment of this study was an overall comparison of the OHF and cased-hole stimulated wells. Expenditures for drilling, completion were included in the analysis. IP's, 3 month, 6 month and 1 year cumulative MCF's were used in the evaluation.
From Geological Knowledge to Good Decisions Using Simple Stochastic Models: A North Sea Case Study
Authors: Hollund K. , Hauge R. , Syversveen A. R. , Jørstad A. , Lie T. , Rønnevik H. C.
Published: December 2007

The decision process for one of the partners in the development of the Alvheim field is presented. The challenge was to turn relatively small Palaeocene structures consisting of both unproven prospects and proven oil and gas reserves into a field development with a good economic performance. The paper describes the stochastic model that was buildt to support decisions in the early phases of the field development.

To pinpoint the essential elements for a model is difficult task. Not only the characteristics of the field, but also the decisions that the model is supposed to support, must be considered. A simple stochastic model was buildt. An exploration type of approach was used. Essential elements are volume-depth curves and modeling of seismic uncertainty and uncertainty in fluid contacts.

Using the model, it was possible to explore important upside potensial seen in geophysical evaluations and answer if and in what sequence further wells should be drilled. An improved understanding of the value for different drilling strategies was gained by studying distributions for in-place oil and gas volumes for various scenarios.
Horizontal-Well Productivity Equations With Both Uniform-Flux and Uniform-Pressure Wellbore Modes
Authors: Chen H. -Y. , Asaad N.
Published: December 2007

This paper concerns the estimation of pseudosteady-state horizontal-well productivity with emphasis on handling two types of wellbore conditions: uniform-flux and uniform-pressure. We present rigorous (analytically) and simplified PI (productivity index) equations which can easily handle the above two wellbore conditions within a consistent framework.

The presented simplified PI equations were verified successfully (i) through detailed mathematical/physical analyses, and (ii) against the more rigorous solutions and published examples, for wide ranges of drainage shape, permeability anisotropy, and well length.
Fluid Characterization for Miscible EOR Projects and CO2 Sequestration
Authors: Jessen K. , Stenby E. H.
Published: December 2007

Accurate performance prediction for miscible EOR projects or CO2 sequestration in depleted oil and gas reservoirs relies in part on the ability of an equation of state (EOS) model to adequately represent the properties of a wide range of mixtures of the resident fluid and the injected fluid(s). The range of mixtures that forms when gas displaces oil in a porous medium will, in many cases, differ significantly from compositions created in swelling tests and other standard PVT experiments. Multicontact experiments, e.g. slimtube displacements, are often used for the conditioning of EOS models applied in performance evaluation of miscible displacements. However, no clear understanding exists of the impact on the resultant accuracy of the selected characterization procedure when the fluid description is subsequently included in reservoir simulation.

In this paper we present a detailed analysis of the quality of two different characterization procedures over a broad range of reservoir fluids (13 samples) for which experimental swelling tests and multicontact data (slimtube experiments) are available. We explore the impact of including swelling test and multicontact data in the data reduction. We demonstrate that swelling tests, in some gas/oil systems, do not contribute to more accurate predictions of multicontact miscibility. Finally, we report on the impact of using EOS models based on different characterization procedures on recovery predictions from dynamic 1D displacement calculations.
Multicontact Miscible Flooding in a High-Pressure Quarter Five-Spot Model
Authors: Dao E. K. , Lewis E. , Mohanty K. K.
Published: December 2007

Miscible and near-miscible gasflooding has proven to be one of the few cost effective enhanced oil recovery techniques. The sweep efficiency of such processes is often not high due to adverse mobility ratio, gravity override and reservoir heterogeneity. Several sweep improvement techniques have been developed, but there is no laboratory technique to estimate sweep efficiency at reservoir conditions. A high-pressure quarter 5-spot cell has been constructed in this work to conduct multicontact miscible water-alternating-gas (WAG) displacements at reservoir conditions. Multicontact miscible solvents are identified by conducting slimtube experiments for a medium viscosity oil (78 cp). Coreflood experiments are conducted to determine microscopic displacement efficiency as a function of WAG ratio. Quarter 5-spot experiments are conducted to infer sweep efficiency in a 3D geometry at the laboratory scale. WAG improves the microscopic displacement efficiency over continuous gas injection followed by waterflood in corefloods. WAG injection improves the oil recovery and thus sweep efficiency in the quarter 5-spot model over the continuous gas injection followed by waterflood. WAG injection slows down gas breakthrough. A decrease in the slug size improves the sweep in WAG floods. Use of a horizontal production well lowers the sweep over a vertical production well during continuous gas injection.
Fracture-Optimized Production Efficiently Stimulates Sandstone Formations With Dunvegan Formation: Case Study
Authors: Leshchyshyn T. T. , Thomson J. D.
Published: December 2007

In the Western Canadian Sedimentary Basin (WCSB), fracturing stimulations have been done for 70 years. In Canada, the government, service companies, and well operators accumulate massive volumes of information. This information exists in the form of paper files and databases of varying detail containing well and treatment information. The information age makes production data available making another leap in determining fracture designs based on real production results of past treatments.

In the past few decades, a common way operators started the design process was to approach service companies for their experience in an area and formation. From around 1955, many new designs were created by referring to old designs. Then the industry used designs that were pumped in the field which progressed in later years to stimulation that were pumped to completion. This sometimes progressed to job designs pumped with production from the stimulated formation. More value is attained by looking at optimal post fracture production using actual results not calculated, uncalibrated predictions. This is most powerful when the production results are matched to calibrated fracture models, reservoir models and petrophysical analysis to continue area projects in stimulated a formation.

This case study covers 3,600 square miles from 58-19W5 to 68-02W6 of the Dunvegan formation. It is a tight, water sensitive formation usually producing gas. Geologically, the Dunvegan has less than 1 mD permeability. The success of various fracturing techniques are evaluated on several levels including a review of the 203 out of the 406 wells in the region. The fracturing strategy comparisons will evaluate base fluid selection, proppant type, and the amount of proppant. The current commodity prices are used to calculate the optimized results versus the vast amount of information that was collected in the past using lower prices.

Hydrocarbon based fracturing fluids were used 85% of the time as one would expect based on the geological evaluation of the area. However, the infrequent and larger water fractures have an IP rate of 1.5 MMscf/day using 100,000 lb of proppant where the more frequent and smaller hydrocarbon fractures are 1.2 MMscf/day using 40,0 lb. Total recovered gas is 4 times higher for the water fractures compared to the hydrocarbon based fractures. The optimization of the hydrocarbon fractures with respect to the pounds of proppant used will also be examined since the most common size was 33,000 lb but was found to have optimal IP gas production using 66,000 lb.
An Integration of Multilevel Local-Global Upscaling With Grid Adaptivity
Authors: Lambers J. , Gerritsen M.
Published: December 2007

We present an iterative method for generating appropriate coarse scale models for adaptive flow simulation in highly heterogeneous reservoir formations. Our approach applies to any strategy for generating structured adaptive grids, but we will focus on Cartesian Cell-based Anisotropic Refinement (CCAR) grids due to their suitability for EOR processes that require aggressive refinement.

We first construct an initial grid that captures the principal flow paths in the reservoir. Refinement is driven by regions of greater heterogeneity in the fine-scale permeability field, which are detected using a connected set approach1. Next, we generate a hierarchy of coarse-scale permeability fields, beginning with the finest scale on the simulation grid. Each field is computed using a local-global upscaling approach2, which employs generic global coarse scale simulations to determine the boundary conditions for the local calculation of upscaled transmissibilities or diagonal permeability tensors. An iteration procedure assures consistency between the local and global calculations. As we proceed to coarser scales, permeability values at finer scales are fixed in order to ensure that fine-scale high permeability flow paths are preserved. This is especially important when simulating gas injection processes because the highly mobile gas will preferentially flow through these paths. Thus we obtain a permeability field that yields an accurate global flow solution with sufficient local resolution where required. Adaptivity eliminates the need to represent permeability with full tensors; diagonal tensors are sufficient.

Furthermore, the combination of adaptivity determined by the connected set approach, and the local-global upscaling (which introduces global connectivities) leads to accurate representation of potential flow paths. Because of this, we significantly reduce process dependency.

For highly heterogeneous (e.g., channelized) systems, this new approach is shown to consistently provide more accurate coarse scale models for global flow in a variety of directions, relative to reference fine scale results, than do existing local, extended local, or local-global upscaling techniques applied to uniform grids.
Next Generation Expandable Completion Systems
Authors: Innes G. , Morgan Q. , Macarthur A. , Green A.
Published: December 2007

This paper documents an 18-month expandable technology research and development effort that has culminated in a system that enables a new approach to reservoir architecture.

The drive for maximum well productivity compels oil and gas companies to consider openhole completion strategies. However, historical uptake has been impeded by inability to achieve effective zonal isolation. The Expandable Reservoir Completion [ERC] combines slotted and solid expandable technology and features a return to conventional unexpanded premium connections to deliver a freely configurable reservoir completion architecture, offering a combination of openhole production performance and cased hole functionality.

Fundamental to the new Expandable Reservoir Completion is a unique, selective rotary compliant expansion technique, which is used to clad the formation wall with expandable screens, slotted liner or solid tubulars with sealing units. This technique facilitates unparalleled flexibility in reservoir design by allowing sections of conventional casing to remain unexpanded between zones. This enables integration with conventional flow control and intelligent completion equipment, ultimately permitting selective isolation & production control.

This paper outlines detailed test data generated by the development program, which included three downhole field trial installations. In addition to this, information from the first global commercial installations will be presented, from pre-job planning through to post installation performance review.

The Expandable Reservoir Completion builds upon existing expandable sand screen and solid expandable technologies to deliver a combination of productivity and functionality previously unavailable to the petroleum industry.
Continuing Education Needs for the Digital Oil Fields of the Future
Authors: Ershaghi I. , Omoregie Z.
Published: December 2007

The increasing demand for cost effective development of oil and gas resources in harsh environments and the need to squeeze more reserves from mature fields have led to an industry-wide push to develop the framework for the digital oilfields of the future1 (called by different names in the industry: "smart fields", "i-field", "efield", "digital oil field of the future", or DOFF,.. etc). Over the past few decades, the world has seen tremendous leaps in the development of hardware and software tools that measure, analyze and optimize process systems. The cost of these tools has continued to decrease. The increased infusion of these technologies in oil and gas asset management has helped many to see greater benefits from making fundamental changes in the infrastructure used to develop oil and gas fields and the work tools and processes used to manage them. Currently available technologies already allow oil and gas professionals to work in a more collaborative environment than ever before. As the industry focuses on developing the technologies required to implement the digital oilfield of the future, the industry must also, simultaneously, focus on the training and recruiting of the manpower qualified to operate digital oilfields. Continuing education must include elements that can provide the practicing professionals with the tools needed to manage the digital oilfield of the future. For students aspiring to join the industry, academia needs to prepare them to manage oil and gas assets with tools and work processes different from what are used today.
Troika Field: A Well Failure, and Then a Successful Workover
Authors: Gillespie G. , Angel K. , Cameron J. , Mullen M.
Published: December 2007

The second phase of Troika field development began in 2000. Two wells were planned to develop reservoirs adjacent to the primary Troika reservoir. The planned wells were deep, single zone, frac packed, subsea completions.

The first of these wells was the Green Canyon Block 201 TA-6 ST#1 Well (TA-6). It was planned to have a well angle exceeding 40°, 7 in. production liner and 4 in. base pipe prepacked screens. After drilling the well, open hole logs showed the target reservoir was approximately 170 ft. thick, but there were two significant shale breaks within the reservoir. During completion, there were problems getting the 7 in. liner to bottom, so a 5-½ in. liner was run. The 5-½ in. liner was cemented in place, and then squeezed due to possible channels across the completion interval. The well was perforated and a 2-⅞ in. reduced diameter prepacked screen was run without difficulty.

During the frac packing process, TA-6 did not have a live annulus, so circulating in this small casing was not possible. In addition, the crossover tool failed during pumping operations. This resulted in frac sand and gel plugging the wash pipe. Consequently, the pressure gauges could not indicate whether a good frac pack was achieved.

TA-6 started production in November 2000 and produced 3.91 million barrels of oil and 4.48 billion cubic feet of gas with water cut slowly increasing to approximately 10% before a gravel pack failure occurred in January 2002. The well was cleaned out and a 1.3 in. diameter through tubing screen insert was run inside the failed screen. No attempt was made to place gravel pack sand between the screen insert and the failed screen. Since the screen insert was installed, TA-6 has produced over 1.95 million barrels of oil and 2.7 billion cubic feet of gas with water cut less than 3%.

This paper will evaluate this well's history using BP's new maximum flux guidelines1. In addition, it will use a new erosion model to evaluate both the probable cause of the well's failure and the operating conditions of the successful workover completion.
Simplifying Hydraulic Fracturing—Theory and Practice
Authors: Hibbeler J. , Rae P.
Published: December 2007

Although hydraulic fracturing is a routine stimulation technique in many parts of the world, it has seen limited use in areas such as Asia Pacific for example. Among the hurdles to fracturing in traditional non-frac markets is the common perception that fracs are expensive, risky, complex and difficult to design. This perception has been challenged in recent years by the promotion and technical validation of simplified fracturing treatments aimed, primarily, to address near-wellbore skin damage. The new approach, termed Skin Bypass Frac (SPF), is low cost, safe, simple, and easy to design. In fact, by careful fluid selection, these small treatments can be pumped from an offshore drilling rig using nothing more than cementing equipment. By simplifying fracturing to this degree, there is now a safer and more environmentally-friendly way to remediate skin damaged wells, without the implicit dangers of acidising.

To date, this technique has been used in a number of diverse situations yet, despite its simplicity, it has yet to be practised on a widespread basis. Results indicate that if candidate selection is good, production increments can be significant, particularly in those wells with skin damage. To make candidate selection effortless, a set of criteria was developed to determine which wells would benefit the most. Parameters such as permeability, zone height, estimated skin, reservoir mobility, zone isolation and proximity to water were all considered in this selection model.

This paper reviews the practical theory of using small simple frac treatments to improve productivity in damaged wells and wells with small sands where higher recovery rates are desired. The concept of LCP is discussed and a model is put forward to perform frac jobs with cement units, which may come to be known as universal pressure pumping units.
The Feasibility Study of Using Underbalanced Drilling in Iranian Oil Fields
Authors: Shadizadeh S. R. , Zaferanieh M.
Published: December 2007

Conventional overbalance drilling in naturally fractured reservoirs causes the invasion of mud and fine rock fragments into the fractures, which result to decrease the productivity of hydrocarbon from these reservoirs. In some cases, the sever problem of mud invasion into the fractured prevents flowing of HC's into wellbore after initial well completion especially in the depleted fractured Iranian reservoirs.

Underbalanced drilling (UBD), with a reduced exerted pressure down in the wellbore avoids the build up small solids being deposited on the sides of the hole, it also prevents the invasion of mud and fine rock fragments into the fractured formation which, together, help to improve the productivity of hydrocarbon from the reservoir. UBD method avoids many of the problems associated with the use of conventional drilling such as stuck pipe. Also, the rate of penetration increase by 2 to 5 folds by using UBD method, which resulted in low cost of drilling.

The main objective of this study is to investigate the use of UBD method in the fractured reservoirs in southern Iranian oil field in terms of drilling equipment's, drilling operation, drilling fluid, formation characteristics, and economic evaluation as compared with conventional overbalance drilling method.
Unconventional Uses for Unconventional Oil
Authors: Ehlig-Economides C. A. , Barrufet M. , Longbottom J. R. , Velu B. P.
Published: December 2007

The correlation of job loss with disruptions in oil supply underscores the importance to the US economy of transportation, which is 95% dependent on oil, the only primary fuel currently being imported by the US in massive quantities. One solution is to promote oil supply stability, but at a sustained higher price, by migrating to unconventional primary fuel resources such as heavy oil, shale oil, tar sands, orimulsion, or coal, that are available on the North American continent. Another solution would be to shift as much transportation as possible to electrically powered vehicles because electricity already uses a diverse selection of energy resources. This paper compares the use of unconventional oil for electric power generation to its use as a source of transportation fuels.

Like coal, unconventional oil can be burned for power generation, or alternatively, both coal and heavy oil gasification processes are described in the literature. Gasification processes can make more efficient use of the energy content, and they reduce atmospheric emissions.

The comparison considers cost, energy efficiency, and environmental impact of the two transportation options on a "well/mine to wheels" basis as well as the estimated coal and unconventional oil reserves.
Combined High-End Technologies Deliver Increased Efficiency in Low-Cost Drilling Environment: Case History in a Western Siberian Field
Authors: Lischuk V. Y. , Brown A. A. , Bakici A. M.
Published: December 2007

In recent years, new technology has significantly improved the economics in high-cost drilling environments worldwide. In a western Siberian case, two service providers recently combined their technologies and operating procedures to yield reduced drilling costs and overall improved project economics. The service companies cooperated to produce the best results for the project and the customer.

This paper describes a project in western Siberia, a well-developed, low-cost environment. Drilling performance had to be measurable and repeatable. The major challenge was to design a polycrystalline diamond compact (PDC) drill-bit/mud-motor combination for use on Russian-made rigs to achieve performance improvement. Issues included tool face control, initial cost of PDC drill bits, and in-country rigs incapable of delivering adequate torque and hydraulic horsepower to the PDC bit.

Applied technology included a new PDC bit designed for steerable motors in projects in which tool face control was a primary concern. The PDC bit was optimized for formation characteristics and motor capabilities by use of depth-of-cut control (DOCC) technology. This optimization reduced torque fluctuations that, in turn, increased tool face control while sliding and increased the rate of penetration (ROP) in rotary mode. Maximizing the benefit of the bit, a special motor was used that was capable of delivering high torque to allow consistently high ROP while maintaining trajectory control. This combination resulted in successful high-performance drilling.

The objective was to complete intervals normally requiring several bits with a single bit run at higher average ROP. The results were indeed rewarding. There were 66% fewer trips per 8½-in. section, on average, compared to offset wells, in conjunction with a 37% reduction in drilling hours, equating to an ROP improvement of 27%. In spite of the additional cost of the PDC and high-torque motor, the system delivered the lowest cost per foot vs. the best offsets from three drilling pads examined. An important feature of the application was that the bit/motor combination was run on a risk/reward incentive program.
What is the Impact of Fracture Modelling on Reservoir Performances and Reservoir Simulation: Examples
Authors: Le Maux T. , Fonta O. , Sarda S. , Godail L.
Published: December 2007

Natural fractures may have a significant role on reservoir performances: fractures may affect wells’ productivity or injectivity. Fractures can also control sweep efficiency and water/gas breakthrough within the reservoir. The purpose of this paper is to present an innovative and rigorous method to identify the main types of fractures, to predict their occurrence in the reservoirs and to determine the hydraulic properties of the different fractures sets. Based on a multi-discipline integrated approach, the end product is a robust and reliable 3D model of fractures properties (porosity, permeability and matrix block size) directly usable for reservoir simulations and predictions.

In the first section of this paper we present how to handle multi scales fractures characterisation through integration of multi disciplinary dataset. In the second section, it will be shown how the fracture characterisation and modelling can significantly improve the history matching process.
A Simulator for Predicting Thermal Recovery Behavior Based on Streamline Method
Authors: Pasarai U. , Arihara N.
Published: December 2007

The general tendency in simulation technique of thermal recovery processes has been to use the fully implicit finite difference method to solve the mass and heat transport. The method has been proven favorable to handle rapidly changing properties and complex physical mechanisms encountered in the processes. However, this method is limited in the grid size due to restrictions in computational power. In addition, the method could also erroneously predict recovery performance if care is not taken in the choice of numerical scheme. For example, when the mobility ratio of the displacement is unfavorable, calculations often result in exaggerated global sweep and may adversely affect reservoir performance prediction. Local grid refinement is a natural process to handle this situation but requires a great amount of memory and high computational cost. This becomes inefficient when multiple simulations are required to assess a wide range of reservoir development scenarios.

An alternative approach to solve the problem is to use the streamline method. Because fluid transport occurs along streamlines rather than between discrete grid blocks on which the reservoir pressure field is solved, the problems associated with the fully implicit finite difference method are minimized and the simulations can run much faster. This is supported by the results presented in this paper. We applied the developed thermal streamline simulator to a hot water-flooding process. Test simulations were performed in the two-dimensional (2D) areal quarter five spot pattern. The heavy oil reservoir is assumed to have undergone cold water injection. Water at the initial conditions is about 45 times more mobile than oil, which leads to unfavorable displacement. The results of simulations are compared with those from the fully implicit method using the 5-point and 9-point finite difference schemes. Although simplified, the simulation demonstrates the main features of our simulator.
Wellbore Cleanup by Water Jetting and Enzyme Treatments in MRC Wells: Case Histories
Authors: Al-Otaibi M. B. , Nasr-El-Din H. A. , Altameimi Y. M.
Published: December 2007

A number of maximum reservoir contact (MRC) wells have been drilled and completed in various fields (sandstone and carbonate) in Saudi Arabia. The drilling fluid, water-based mud, consists of xanthan, starch, polyanionic cellulose polymers and bridging agents like sized calcium carbonate or salt particles. Cleanup of drilling fluid filter cake in long horizontal wells completed as an open or cased hole is a challenging task. The obstacles encountered are the difficulty to ensure contact of the treating fluids with the filter cake throughout the whole interval, as well as controlling the reaction rate between the breaker and the filter cake to ensure uniform removal of the filter cake.

Today, several chemical and mechanical systems are available to remove the polymeric and bridging agents in oil and gas producers and water injectors. Chemical means (oxidizers and acids) have limitations, which can adversely affect well performance. Oxidizers and acids are highly reactive and non-specific species. Reservoir heterogeneity complicates the cleaning process. There is a need for cleanup fluids that have a delayed effect on filter cake-integrity to obtain a uniform distribution over the horizontal interval.

Specific enzymes can degrade xanthan and starch polymers in the filter cake with lower removal rates. A low reaction rate promotes a more uniform cake cleanup and should result in higher production rates. Field results indicate that utilization of enzyme treatments is very effective technique in removing drilling mud filter cake. The production rate for treated wells reached the target value without the need to acidize the well.

High pressure water jetting technique has been utilized to mechanically remove filter cake. Field results obtained from many injectors indicate that this technology has several advantages such as simplicity of use, cost effectiveness, and high success rate. This paper will discuss field application of specific enzymes and water jetting in gas, oil, and water wells. It will also highlight the advantages and disadvantages of each method based on field data.