bluuebunny/crossref_metadata_2025 huggingface dataset:
Improved Techniques to Alleviate Sustained Casing Pressure in a Mature Gulf of Mexico Field
Authors: Soter Kevin , Medine Felix , Wojtanowicz A. K.
Published: December 2007

The objective of this paper is to highlight the techniques used during a recent workover program to alleviate sustained casing pressure in a Gulf of Mexico field. Discussion will include cement and workover fluid programs, hole preparation before milling and cementing operations, and improved milling procedures.

The field was drilled during the 1980s and sustained casing pressure has been prevalent in some cases previous to initial completion operations. In two rig workover programs in 1989, and again in 1990, a total of nine temporary abandonments were attempted. These programs resulted in limited success until the most recent workover program beginning in 1999. In addition, a non-rig program was running concurrently with the most recent rig operations in an attempt to avoid rig intervention when possible. However, this system will not be discussed in this paper except as it applies to specific operations.

All indications are that the workover program was successful even though there was some need for remedial rig work on three wells while operations were ongoing. A review of past attempts, relying on internal correspondence and drilling reports, will be made and compared to the present 1999 rig operations program using first hand knowledge of the operations and decisions.
Continuous Rock Strength Measurements on Core and Neural Network Modeling Result in Significant Improvements in Log-Based Rock Strength Predictions Used to Optimize Completion Design and Improve Prediction of Sanding Potential and Wellbore Stability
Authors: Suárez-Rivera Roberto , Ostroff Gary , Tan KaiSoon , Begnaud Bill , Martin Wesley , Bermudez Tony
Published: December 2007

The scaling-up of laboratory rock mechanical measurements from sample-scale to reservoir-scale is fundamental to evaluation of wellbore stability, sanding potential, reservoir compaction or casing failure. Understanding rock heterogeneity is fundamental for adequate scaling-up laboratory measurements to core- and reservoir-scales and thus, to predictions of mechanical failure. Historically, scaling-up from core scale to reservoir scale has been dependent on calibration of log-based models to a sparsely sampled data set of rock mechanical property measurements made on core plugs. Such a sparsely sampled data set of core plug measurements alone may inadequately characterize the range heterogeneities in the reservoir, resulting in less than optimum log-based predictive models. With the introduction of continuous, high resolution, rock strength (UCS) measurements on core via scratch testing, an excellent calibration reference for producing robust log-based predictions of rock strength now exist.

In this study, high-resolution measurements of strength heterogeneity were obtained as a function of core length and were correlated with fundamental textural and compositional parameters from petrographic analysis. Using adaptive learning neural networks, fundamental relationships between log measurements and rock strength were obtained. This methodology was adequate for characterizing the intrinsic rock heterogeneity at appropriate scales for mechanical analysis of completion design and sanding (0.25 ft). The methodology is also potentially applicable to the scaling-up of other fundamental mechanical properties such as in-situ strength, compressibility and thick-walled cylinder strength.

Results show that intrinsic textural heterogeneity and strength heterogeneity are strongly related in sedimentary rocks. Recognizing the importance of rock heterogeneity and being able to scale-up this property to core and reservoir scales via log measurements results in significant improvements in the predictive capacity for sanding potential and wellbore stability. For example, thin layers of considerably weaker-strength than the surrounding rock, undetectable from conventional log-based rock strength predictions, were detected and included in the mechanical model. In addition to possessing high sanding potential, these weaker sections are also regions of fluid loss during drilling. Results can be used for selection of competent rock across the field (based on LWD measurements) for multilateral junction placement, and for selection of optimum completion strategies.
High-Temperature Wells with Lost-Circulation Demands and Reverse Circulation Placement Technique Using Foamed Cement Systems: Two Case Histories
Authors: Moore Robert , Bour Daniel L. , Reed Shawn , Hernandez Rafael
Published: December 2007

Drilling activities in diverse areas can pose significant challenges for conventional cement systems and circulation methods. To overcome these challenges, a unique cementing system and circulation method has been tested in the field with great success. This paper details how these technologies and techniques were successfully used in the cementation process of one casing string in a relatively shallow geothermal well in central California and a relatively deep string in central Wyoming.

Globally, a great many wells experience lost-circulation problems that require the reduction of circulation pressures to allow proper placement of cement to provide annular coverage. To help minimize these circulation pressures, cement was pumped into the annulus directly, significantly reducing placement pressures and allowing placement of the cement with no apparent losses—a process referred to as the reverse circulation placement technique (RCPT). In each of the deep and shallow applications discussed, the placement technique and the individual slurry designs address temperature issues.
Using Spectral Decomposition for Integration of Multi-Scale Data in High Resolution Reservoir Modeling
Authors: Gilbert Fabien , Andrieux Benoit
Published: December 2007

The spatial heterogeneity of rock properties within a hydrocarbon reservoir has a large effect on fluid flow. Reservoir heterogeneity can be described over a wide range of spatial scales. Each data source that is integrated into the geological model represents a specific scale of information. For example, well data generally provide finer-scale information than do seismic data. The proper integration of different data types into the geological model should account for their difference of scale. Recently, several geostatistical methods have been developed to account for variation in different scales of heterogeneity. Deficiencies in those methods include an inability to identify spatial components that have physical interpretations (factorial kriging), a difficulty in controlling model perturbations (sequential gaussian simulation with non stationary kriging or block cokriging). These deficiencies are particularly true when integrating seismic information into the geological model. In this context, we propose a methodology which allows integration of reservoir properties (known at wells, with high vertical resolution) and seismic attributes (laterally dense but with low vertical resolution) overcoming these deficiencies. Our methodology is based on a spectral decomposition of high resolution well information using spectral characteristics of seismic attributes. Different components are then simulated with seismic information as a constraint for the component which bandpass is consistent between well and seismic data. All components are then recombined and transformed to generate the desired reservoir property. This methodology is evaluated against others in terms of easiness of implementation, computing time, impact of the seismic data and similarity to a synthetic model. An application of this methodology to a real data set is presented. The geological environment of the reservoir is a mixed carbonate platform. Porosities are simulated at a fine scale constrained by a 3D impedance cube.
Quantitative Use of 4D Seismic Data for Reservoir Description
Authors: Dong Yannong , Oliver Dean S.
Published: December 2007

4D seismic or time-lapse seismic is the process of repeating 3D seismic surveys over a producing reservoir to monitor changes in saturation and pressure. Repetition of measurements makes it possible to eliminate the effects of unknown static reservoir properties to focus on the dynamic changes in production related properties.

While there are many simple and direct methods of using time-lapse seismic data based on the study of rock properties alone, these tend to ignore constraints on saturation and pressure imposed by mass conservation and flow relationships. In contrast to other research work, this paper gives a way to use seismic impedance change data in an automatic history matching procedure. We use a finite-difference, black-oil reservoir simulator, with rock physics included, to predict seismic impedance as a function of saturation and physics. The adjoint method for computing derivatives is used with a quasi-Newton minimization method to efficiently minimize the difference between observed impedance changes and the impedance changes predicted using the reservoir simulator. The permeability and porosity of simulator grid-cells are adjusted iteratively during the minimization process. The feasibility of this method of utilizing time-lapse seismic data is illustrated with an application to a semi-synthetic model created from a large middle-eastern oil field. A primary conclusion is that the spatial distribution of seismic impedance change data is helpful in reducing the uncertainty of the estimates of reservoir parameters.
Passive Imaging of Seismic Deformation Associated With Steam Injection in Western Canada
Authors: Maxwell S. C. , Urbancic T. I. , Prince M. , Demerling C.
Published: December 2007

Passive seismic imaging of reservoir deformation is potentially a powerful technique to monitor a number of reservoir operations, including steam injection for enhanced recovery. In this paper, we describe the seismic deformation associated with steam injection in a Western Canada heavy oil field. The seismic deformation images show the steam movement in the reservoir. The seismic deformation was compared with other reservoirs, including gas injection in an East Texas field, two compacting North Sea fields, and hydraulic fracture stimulations. Similar deformations were observed for this wide variety of sites, although the deformation occurred at different rates for the different examples ranging from a few hours in the hydraulic fracture examples to over several months in the gas injection. Nevertheless, the recording of similar deformation levels at these various sites bodes well for broader application of the passive monitoring in other fields.
Uncertainties in Mapping Salt Flanks with 3D Salt Proximity Survey
Authors: Li Y. , Jackson J. , Espinosa S. , Faw D.
Published: December 2007

This paper presents the results from a study on uncertainty analysis for mapping salt flanks with a salt proximity (SP) data set acquired in the Gulf of Mexico, where petroleum reserves are often trapped underneath overhangs of diapiric salt domes. Determination of the precise location for the salt face will help petroleum engineers to find an optimal drilling path to hit the target reservoir and allow geoscientists to obtain the best estimate for the size of the reservoir.

Measurement errors of arrival times, azimuths, and vertical angles of the first breaks of SP data were estimated and their effects on the solutions of the salt face were calculated. Sensitivity tests were carried out to evaluate mapping uncertainties caused by the parameter variations of the 3D salt and sediment models. The salt face solution and associated error bars were integrated with well control data, offset VSP migration, and a surface seismic profile to interpret the steep salt flank and surrounding sedimentary rocks.
Innovative Proppant Flow-Back Control Yields 100% Success in Permian Basin
Authors: Rodgerson James L. , Friesen Bruce E. , Entzminger David J. , Brown Tom , Anderson Shawn
Published: December 2007

The Martin Field is located in the southwestern portion of Andrews County, Texas on the eastern flank of the Central Basin Platform of the Permian Basin. Although the field was discovered in 1945 with the Ellenburger and San Andres producing horizons, the Leonardian, Clear Fork and Wichita were not exploited until the early 1980's. The reservoir rocks in the Leonardian are a series of subtidal and intertidal, shallow shelfal dolomites. In general the reservoir intervals are poorly connected and are relatively tight, requiring stimulation to make these wells economic. These wells typically have large treatment intervals (200 to 300 ft) with multiple horizons.

Previously wells in this area would require additional well work to clean up proppant production and repair damaged pumps even after the initial clean-up period. With the advent of a new proppant flow-back control technology, repair costs have been eliminated and post frac clean-up time dramatically reduced.
CO2 Compatible Non-Aqueous Methanol Fracturing Fluid
Authors: Gupta D. V. S. , Niechwiadowicz G. , Jerat A. C.
Published: December 2007

Stimulations and sand control treatments using non-aqueous systems, particularly for water-sensitive formations have been successfully used in the industry. Non-aqueous systems include hydrocarbons and alcohol. Alcohol provides several advantages in formation compatibility, retained conductivity, clean-up and enhanced productivity. In addition, non-aqueous alcohol removes any water or emulsion blockages. Adding carbon dioxide as an energizing medium to assist fluid recovery to the well bore after treatment, especially in low or under-pressured reservoirs is an accepted practice.

Conventional guar and derivatives do not gel non-aqueous alcohol systems. Previously described modified guar, which viscosifies non-aqueous alcohol, is not compatible with CO2. Without adding water, it is considered difficult to degrade non-aqueous alcohol gels with oxidizing breakers.

This paper describes a new non-aqueous alcohol-based fracturing fluid, compatible with CO2, that can be efficiently broken across a wide temperature range. The unique system meets rheological requirements for fracturing, can be energized with either nitrogen or carbon dioxide, and can be broken using a unique oxidizing breaker system.
Accurate Prediction Wellbore Transient Temperature Profile Under Multiple Temperature Gradients: Finite Difference Approach and Case History
Authors: Chen Zhongming , Novotny Rudolf J.
Published: December 2007

Failure to estimate the correct temperature during cementing operations can often lead to long delays in rig operations or can allow the flow of gas or water from shallow over pressured formations. API (American Petroleum Institute) Sub-committee 10 (Well cements) has developed methods to determine the bottom hole circulating temperature (BHCT) for the proper design of cementing slurries. These methods work adequately in most cases. But, in wells that are deviated and have multiple temperature gradients like those found offshore in deep water basins, these methods are inadequate.

This paper presents a finite difference model developed to predict the wellbore and formation transient temperature behavior during fluid circulation in the wellbore. It also provides the information on temperature recovery after the cement slurry becomes static. Emphasis is placed on evaluation of wells with multiple temperature gradients, multiple fluid circulation schedule, and wellbore deviations. The effect of offshore water currents is also discussed.

The predictions of the wellbore temperature profiles and return temperatures from this model are validated through actual measured wellbore temperature profile history, including offshore and onshore cases. The paper also discusses the impact of job execution parameters such as fluid density, flow rates, inlet temperature, and fluid rheology. Guidelines are provided to help the engineer design an optimal working schedule to achieve one's particular goal of controlling wellbore temperature at desired level during actual cement placement operation.
The Benefits of Very High Paraffin Drill Mud Fluids and Their Advantages for Cuttings Disposal
Authors: Fefer M.
Published: December 2007

The use of diesel to formulate onshore drilling fluids has been ubiquitous in North America. Recently however, a number of operators have abandoned using diesel in favor of more environmentally acceptable fluids such as those afforded by waterbased drilling fluids or high paraffinic fluids. The latter type are especially useful in high temperature, high pressure extended reach applications. In addition, the newer all-paraffinic fluids possess reduced toxicity and reasonable biodegradability characteristics. As such, they are excellent candidates for a variety of drilling applications and for cuttings remediation approaches including composting.
Controls on Recovery Factor in Fractured Reservoirs: Lessons Learned from 100 Fractured Fields
Authors: Allan Jack , Sun S. Qing
Published: December 2007

One hundred fractured reservoirs from around the world were evaluated to determine how ultimate recovery was affected by inherent reservoir and fluid properties, such as porosity, permeability, viscosity, mobility ratio, Sw, wettability, fracture distribution, and drive mechanism vs the choice of reservoir management strategy, e.g., optimization of production rate and type of EOR technique. Fractured oil reservoirs were divided into four groups. Type I reservoirs have little matrix porosity and permeability. Fractures provide both storage capacity and fluid-flow pathways. Type II reservoirs have low matrix porosity and permeability. Matrix provides some storage capacity and fractures provide the fluid-flow pathways. Type III (microporous) reservoirs have high matrix porosity and low matrix permeability. Matrix provides the storage capacity and fractures provide the fluid-flow pathways. Type IV (macroporous) reservoirs have high matrix porosity and permeability. Matrix provides both storage capacity and fluid-flow pathways, while fractures merely enhance permeability.

Previous fractured reservoir classifications did not distinguish between Type II and Type III reservoirs, instead combining all fractured reservoirs with low matrix permeability together into one group. By cross-plotting the various reservoir properties vs ultimate recovery factor and reviewing case studies of primary and enhanced recovery history for 26 Type II and 20 Type III reservoirs, it is demonstrated that recovery factor is controlled by different factors in these two reservoir types. Recovery factor in Type II reservoirs is sensitive to aquifer-drive strength and optimization of flow rate. Type II reservoirs are easily damaged by excessive production rates, but when managed properly, some achieve good recovery without the need for secondary or enhanced recovery programs. Recovery factor in Type III reservoirs is affected by inherent rock and fluid properties, particularly matrix permeability, API gravity, wettability, and fracture intensity. The choice of proper EOR technique is essential for optimum exploitation. No Type III reservoir is produced to final depletion without the aid of some type of secondary or EOR technique. Recognition of the differences between Type II and Type III fractured reservoirs should lead to better choices of exploitation strategy.
Iterative Integration of Dynamic Data in Reservoir Models
Authors: Kashib Tarun , Srinivasan Sanjay
Published: December 2007

Conditioning reservoir models to dynamic data such as historical production response is challenging because of the complexity of the relationship between the model parameters and the response variable. The focus of this paper is to present a methodology for efficiently integrating dynamic production data into reservoir models. In contrast to some of the other methods, the proposed methodology attempts to quantify the information in production data pertaining to reservoir heterogeneity in a probabilistic manner. The conditional probability representing the uncertainty in permeability at a location is iteratively updated to account for the additional information contained in the dynamic response data. A localized perturbation procedure is also presented to account for multiple flow regions within the reservoir. Such an improved scheme utilizes a set of locally varying deformation parameters to guide the iterative updating process in order to obtain a global history match.
Automatic History Matching of Geologic Facies
Authors: Liu Ning , Oliver Dean S.
Published: December 2007

The truncated pluri-Gaussian method for modeling geologic facies is appealing not only for the wide variety of textures and shapes that can be generated, but also because of the internal consistency of the stochastic model. This method has not, however, been widely applied in simulating distributions of reservoir properties facies or in automatic history matching. One reason seems to be that it is fairly difficult to estimate the parameters of the stochastic model that could be used to generate geological facies maps with the desired properties. The second is that because "facies type" is a discrete variable, it is not straightforward to apply the efficient gradient-based minimization method to generate reservoir facies models that honor production data. Non-gradient methods, however, are too slow for large field-scale problems.

In this paper, the non-differentiable history-matching problem was replaced with a differentiable problem so that an automatic history matching technique could be applied to the problem of conditional simulation of facies boundaries generated from the truncated pluri-Gaussian method. The resulting realizations are consistent both with the geostatistical model of the observed facies and the historic production. Application of the method requires efficient computation of the gradient of the objective function with respect to model variables. We present an example five-spot water injection problem with more than 73,000 model variables conditioned to pressure data at wells. The gradient was computed using the adjoint simulator method, and the minimization routine used a quasi-Newton method. The data mismatch decreased more than 90% in the first two iterations.
Semi-Analytic Calculations of Horizontal Well Productivity in Fractured Reservoirs
Authors: Fokker Peter A. , Verga Francesca , Egberts Paul J. P.
Published: December 2007

Simplified analytical relations derived for homogeneous formations are usually applied for the determination of the productivity of horizontal wells regardless of the presence of heterogeneities in the reservoir. Furthermore, complex well architectures and the wealth of completion options currently available can not be properly taken into account, because the well trajectory can only be schematized as a single horizontal wellbore. However, the use of numerical reservoir simulators to reliably forecast the productivity of horizontal wells draining heterogeneous reservoirs may be time-prohibitive or not feasible due to lack of sufficiently detailed information, especially during the appraisal phase or the early stages of production.

A new semi-analytic technique is proposed in this paper to solve the inflow equations in an approximate yet reliable manner. The solution to 3-dimensional problems of singlephase flow into a horizontal well, taking into account friction in the wellbore, is provided for both single-layer reservoirs and reservoirs comprising two interfering layers. The method has been extended also to describe the fluid flow when the well intercepts one or more fractures. The presented technique allows very fast calculation of the well productivity in oil and gas reservoirs offering great flexibility in the placement and architecture of the wells.

The method has been applied to two field cases for which the well productivity under pseudo steady-state conditions was measured. One of these is a 200-m long horizontal well draining an isotropic carbonatic reservoir and intersected by a natural low-conductivity fracture. The other is a similar well, intercepting a natural high-conductivity fault, but the oil-bearing formation is anisotropic. Good correspondence was found between the actual productivity and the predictions obtained by application of the proposed semi-analytic technique.
3D Simulation of Array Induction Logging in a Deviated Well Environment: A Mahakam Delta Case Study
Authors: Tarouilly Loic , Rabinovich Michael , Wang Tsili , Pedron Bruno
Published: December 2007

Array induction measurements have been routinely used in the Mahakam Delta, Indonesia, in near vertical wells with oil-based mud and little or no washouts. In these conditions, even a small separation of the shallow focused curves from the deep curves gives a reliable indication of the mud filtrate invasion. The presence or absence of resistive invasion has been used as an indicator of water or hydrocarbon-bearing reservoirs. However, in deviated wells (above 30-40 degrees) the standard focused induction curves may exhibit erratic spikes and curve separation. Therefore, without proper corrections for the dip effects, the separation of the focused curves cannot be used as a reliable indicator of invaded zones and consequently for hydrocarbon typing in deviated wells. To investigate the effects of the relative dip on the array induction measurements in the Mahakam Delta's specific environment of thinly laminated shaly sands and whether these effects can be properly dealt with, a 3D forward modeling project was conducted.

Two 80-m intervals were selected from a neighboring vertical well to build a resistivity model. 2-D inversion was applied to recover the bed boundaries and resistivities. The resistivity model was used in the 3-D forward modeling to produce an array induction response in the 45-degree deviated well. To reduce the computational costs, intervals with no invasion were simulated with a 1-D modeling algorithm without a borehole, since the borehole effect could be easily corrected for the oil-based mud. The 3-D synthetic response combined with the 1-D response for both standard vertical well processing and well-site enhanced processing (Inhomogeneous Background Focusing -IBF) allowing for the dip-effect correction. The results clearly indicate that the dipping bed effects for the 45-degree deviated well can significantly distort the focused curves, if data are processed as in a vertical well. These distortions manifest themselves as an artificial separation that does not permit fluid typing. After the dip-effect correction with the IBF processing, the focused curves show no separation in an uninvaded formation (as desired) and depict appropriate separation in invaded layers, which again allows for reliable fluid typing.
Classifying Crude Oil Emulsions Using Chemical Demulsifiers and Statistical Analyses
Authors: Poindexter Michael K. , Chuai Shaokun , Marble Robert A. , Marsh Samuel C.
Published: December 2007

Crude oil emulsions are highly complex mixtures that can be stabilized by a number of naturally occurring species and conditions (e.g. asphaltenes, resins, acids, solids, solvency, viscosity, temperature, etc.). Emulsion resolution is often accomplished using chemicals. Optimization of chemical treatment is generally accomplished in the field by bottle testing a large number of potential chemical intermediates and their combinations. Successful chemical formulations are able to drop water rapidly, provide relatively clean interfaces, and produce dry, saleable oil.

The very nature of bottle testing produces a large amount of data. Some of the data provides information regarding water drop, while part focuses on breaking the emulsion (i.e. producing dry oil and clean interfaces). To summarize results from multiple test sites, a highly structured bottle test was devised to make comparisons among different oilfield emulsions. Thirty-eight chemical intermediates, tested at two dosages, were evaluated at nine different sites. From the testing, ten bottle test performance parameters (four describing water drop, three describing oil dryness, and three describing the oil-water interface) were analyzed using several statistical methods: analysis of variance, multivariate correlations, cluster analysis, and principal component analysis. The analyses revealed a number of interesting trends. For example, the water drop and oil dryness parameters were found to be more independent of one another than the water drop and interface parameters. These results suggest that water drop and oil dryness are likely governed by two different mechanisms. This work has resulted in several emulsion "maps" where crudes can now be classified with regard to their ability to drop water and break emulsion.
Computer Modeling and Simulation of Coalbed Methane Reservoir
Authors: Guo Xiao , Du Zhimin , Li Shilun
Published: December 2007

The development of a three-dimensional coalbed-methane (CBM) numerical reservoir simulator is presented for modeling flow mechanism of coalbed methane gas reservoir and predicting its production performance. This model is a diphase (gas-water) mathematical model of applying dual grid system, and three processes, i.e. desorption, diffusion and percolation flow, undergone by coalbed methane from the coal matrix surface into wellbore are considered in the simulator. On the basis of the real gas law, Darcy's law and continuity equation, a mathematical model was established and numerically solved by use of differential discrete method; the coefficient term and production term in the equation were explicitly dealt with; and the implicit format treatment and solution were adopted to acquire the parameters and the amount of mass exchange of the coal matrix-cleat system. In addition, the program source code was written; through analyzing and contrasting examples, the simulator proved efficient and reliable in modeling the behavior of coalbed methane reservoir. The new model we have developed also permits to precisely describe the phenomena occurring within the coal cleats and micropores, and to be better understanding the production mechanisms of coalbed reservoir.
Application of Innovative Technologies to Fractured Devonian Shale Reservoir Exploration and Development Activities
Authors: MacDonald R. J. , Frantz J. H. , Merriam G. W. , Zyglowicz P. A.
Published: December 2007

This project was conducted under the auspices of NYSERDA contract 4881-ERTER-ER-99 with its primary purpose to obtain and utilize "ground-truth" data collected from two Upper Devonian Shale wells. With this information, a better understanding of the productive potential in western New York has been obtained. Both wells (W. Stein Unit #2 and S. Preston #8) were drilled in August 2001 by Great Lakes Energy Partners, LLC and are located in Athens field, Crawford County, Pa. adjacent to the Tyrone Mount Union lineament. The wells were completed open hole without any stimulation. Numerous technologies were used to acquire this information including running geophysical logs, gas sample analysis, and examining ten rotary sidewall cores from the Stein Unit #2. From this data, various models were built to characterize geologic, reservoir, and fluid flow characteristics, which were used to estimate gas in place, bulk permeability, and deliverability.

Though the existent natural fracture systems provide conduits from the reservoir to the wellbore, the shale in this area contains only a limited quantity of gas-in-place and is exceptionally lean in organic content. Permeability studies indicate this is a dual porosity system producing primarily via the fractures, and to a lesser extent from the matrix. Very little adsorption of gas is present and the reservoir is relatively low in organic content. An analysis conducted by the University of Michigan reveals that the gas is primarily thermogenic in origin with possible traces of biogenic origin. The results of this paper are significant in that it provides a better understanding of the production mechanisms of the reservoir within a localized area.

Based on the results of this study, the following conclusions are provided: The Upper Devonian Shale in this immediate area is extremely lean in organic content as indicated by its low Total Organic Carbon (TOC) = 0.36%. As a point of reference, many productive shales have TOC values ranging from 1-9%.Shales in this immediate area are a limited source of hydrocarbons (~27 Mscf per acre-foot).The gas is thermogenic with trace amounts of biogenic origin.Very little adsorption of gas is present.Both test wells are located in an area of natural fracturing adjacent to the Tyrone Mount Union lineament, which most likely provides a conduit for natural gas production.Relative to other producing shales, the reservoir is comparatively poor near the test wells.Production data analysis indicates a dual porosity system producing primarily through fractures and to a lesser extent, via the matrix.Estimated ultimate recoveries range from 1.1 to 3.0 MMscf, and drainage areas are 1.325 and 2.0 acres for the Preston #8 and Stein Unit #2 respectively, assuming no stimulation.
The Relationship Between Net Pressure Development During Hydraulic Fracture Treatments and Productivity in Fruitland Coal Completions
Authors: Jordan Jeff S. , Harkrider John D. , Anthony William L. , DeLong Thomas W. , Martin Ray F.
Published: December 2007

This paper describes an innovative fracture treatment design approach that has been successfully used to improve the productivity of Fruitland coal CBM completions. The process integrates real-time treating pressure evaluation to adjust key treatment parameters on the fly and maintain a low net pressure development. The low net pressure development indicates good proppant distribution through the created fracture geometry and minimizes potential formation/fracture damage from the fracturing fluids. This results in shorter de-watering periods and accelerates peak production of the Fruitland Coal completions.

In the Fruitland Coal, the dominant fracturing mechanism controlling the ability to distribute proppant laterally into the far-field is the quality of the near-wellbore connection. Complex near-wellbore fracture geometries result in a convoluted slurry pathway, which hinders lateral proppant distribution into the far-field. Further, if the near-wellbore connection was not mitigated effectively, the overall net pressure development while placing proppant became excessive. This paper discusses the innovative changes made to improve the near-wellbore connection, allowing the treatment to be completed and productivity of the well increased.

Based on an offset well study, it was observed that excess net pressure development damaged the fracture conductivity and/or the cleat system of the coal. When an excessive level of net pressure was developed, polymer dehydration into the cleat system caused irreparable damage to the existing permeability. Evidence of the damage was indicated by the extended load fluid recovery time. Since de-watering of the coal begins only after the load is recovered, it was observed that gas production was significantly delayed when the net pressure development during the propped fracture treatment was excessively high.

Observing this relationship, treatment designs were altered, but more importantly, real-time assessment of the treatment pressure character was found to be essential in achieving design objectives. The completion approach discussed in this paper has been employed in over thirty-five Fruitland Coals completions over the past three years with excellent production results.
Analysis and Optimal Design of Gas Storage Reservoirs
Authors: Kuncir Mark , Chang Jincai , Mansdorfer Jim , Dougherty Elmer
Published: December 2007

Gas storage plays an increasingly important role in managing gas supply. Developing and operating gas storage reservoirs more effectively is a key component of minimizing cost and assuring continuous supply to consumers[1,2,3]. Here we demonstrate the benefits gained from use of a comprehensive set of computer tools to interpret performance and devise optimal operating and investment plans for storage reservoirs. These tools treat engineering and economic factors simultaneously in an integrated framework. However, speed and convenience are achieved via use of aggregated models. Efficient search and curve-fitting routines allow rapid assessment of potential impact of missing or uncertain data. These programs are especially useful in the planning stage of storage reservoir development where complex multi-cell reservoir simulators may not be cost effective.

In this paper, we present the results of four case studies: Final blowdown of a storage reservoir.Optimal design of expansion of a storage reservoir.Size and impact of a storage reservoir's aquifer.Potential impact of data uncertainty on an oil reserve estimate.
Paraffin Problems in Gas Systems
Authors: Barker K. M. , Bigler J. M. , Hake K. , Sallee D. C.
Published: December 2007

Gas wells, coal seam methane wells, glycol dehydrators, gas plants and gas storage wells can all experience paraffin problems that affect the cost to produce and handle gas. Problems with paraffin have been encountered from the formation through the gas plants to the storage wells. This paper will explain what paraffin is, why the problems occur and what type of treatments have effectively treated gas system problems. Case histories of various types of successful and unsuccessful treatments will be presented.
Numerical Investigation of Laser Drilling
Authors: Bjorndalen N. , Belhaj H. A. , Agha K. R. , Islam M. R.
Published: December 2007

The need for a new method of drilling oil and gas wells is immense. Current drilling techniques used were developed at the beginning of the last century. Many problems persist with this method including downtime due to dull bits, the lack of precise vertical or horizontal wells and formation fluid leakage during drilling due to the lack of a seal around the hole. Laser drilling is a new technology that has been proposed as a method to eliminate the current problems while drilling and provide a less expensive alternative to conventional methods. Although lasers have found widespread use in many industries, it is only recently that research in this area has been redirected to the oil and gas industry.

A numerical model was developed and verified with previously published experimental data. A detailed parametric study is included and experimental design considerations are discussed. Laser drilling has great potential to revolutionize the oil and gas industry. Design considerations for a field application are presented, with discussion on economical and environmental impacts.
Liaohe Extra-Heavy Crude Oil Underground Aquathermolytic Treatments Using Catalyst and Hydrogen Donors under Steam Injection Conditions
Authors: Zhong L. G. , Liu Y. J. , Fan H. F. , Jiang S. J.
Published: December 2007

The aquathermolysis of Liaohe heavy oil is described which involves the addition of catalyst and hydrogen donors under steam injection conditions. The laboratory aquathermolytic experiments were carried out with the heavy oil, water, catalysts, and hydrogen donors at different temperature (160~260°C) and reaction time (24~240 hours). It was found that the metal species could catalyze the aquathermolytic reactions of Liaohe extra-heavy oil, for example, Fe(II) led to near 60% decrease in viscosity of treated oil at 240°C till 72 hours. However, using catalyst and hydrogen donor (tetralin), more decrease (up to 90%) in viscosity was observed, it indicated the synergetic effect of hydrogen donor and catalyst on aquathermolysis. Average molecular weight, element and SARA analysis showed the same synergetic effect. A cheaper hydrogen donor almost as effective as tetralin was developed from coal tar. The field aquathermolytic testing using catalyst and hydrogen donor were carried out at five Liaohe extra-heavy oil wells, as a result, the oil recovery was improved and treated oil upgraded greatly.
A Procedure for Upscaling Two-Phase Flow in 2D Heterogeneous porous Media
Authors: Virnovsky G. A. , Kløv T. , Øren P. E. , Stensen J. Å. , Lerdahl T. R. , Berge L. I. , Kleppe H.
Published: December 2007

In order to model a WAG process in a North Sea oil field integrated pore-to-field scale multiphase upscaling was performed[1]. The upscaling procedure included two steps. A pore-to-core upscaling step was based on pore network modeling. It resulted in relative permeabilities and capillary pressure functions, which represent the Darcy-scale properties of rock types. The saturation functions were utilized in the next upscaling step.

In this paper we describe the second upscaling step, from centimeters to meters scale, which was performed to derive multi-phase flow functions for the field-scale simulation. This step takes into account heterogeneity of the facies as well as gravity effects, and is based on steady-state upscaling technique. The upscaled flow functions resulting from the second step depend both on the flow direction and on the flow rate (or pressure gradient). The rate sensitivity of the upscaled functions is different for the two directions, horizontal and vertical. The upscaled flow functions in the horizontal direction are rate insensitive, while the vertical flow functions appear to be quite sensitive to the vertical rate.

Derivation, analysis and validation of the upscaled flow functions are described. The latter is done by comparison of the fine grid simulation and homogenized coarse grid simulation in 2D, vertical crossection, and also by comparison of the predicted oil production with field observations.
Can We Ignore Asphaltene in a Gas Injection Project for Light-Oils?
Authors: Sarma Hemanta K.
Published: December 2007

When light-oil reservoirs are considered for miscible gas injection processes (with CO2 or hydrocarbon gases), more often the potential of asphaltene precipitation is either overlooked or not anticipated for two seemingly compelling reasons: first, the asphaltene content in most light-oil reservoirs where gas injection is implemented could be minute, and second, the reservoir has had no prior experience of asphaltene precipitation during its primary production phase. As a consequence, the potential of asphaltene precipitation occurring during gas injection does not get the careful attention it deserves. Operators are often confounded and taken by surprise when they experience a manifestation of serious asphaltene precipitation soon after the gas injection starts. Once the asphaltene precipitation occurs, it causes severe permeability reduction and wettability alteration in the reservoir, and plugging in the wellbore and surface facilities. Remedial measures, which are expensive and disruptive, usually include chemical treatments and workover operations are often disruptive and expensive. Therefore, one must investigate the possibility of asphaltene precipitation prior to implementing a gas injection scheme.
Radical Approach to Water Injection Scheme for Barton
Authors: Sathyamoorthy S. , Priyandoko P. , Flatval K. B. , Bulang A. , van den Hoek P. J. , Qiu Y.
Published: December 2007

Fractured injection is not new to the oil and gas industry, and occurs unintentionally in most water injection schemes. However, deliberate fractured water injection is usually not evaluated upfront in order to derive optimal cost and recovery, and open-up opportunities for further optimization. The initial design for water flooding in Barton was based on a full-blown conventional water treatment plant on a new platform for seawater injection under matrix conditions.

Fracture simulation work revealed that in the case of Barton, by relaxing water quality induced fractures are not expected to be excessively large and cause any concerns on integrity of the reservoir and nearby wells. Owing to a lower required injection tubing head pressure than previously believed to achieve fractured injection only relatively low pressure and cheap injection pumps are required. Additionally, fractured water injection has allowed for the introduction of raw-seawater injection, whereby the significantly smaller water treatment facility than previously required for matrix injection is placed on a deck extension from an existing platform.
Characterizing Partially Fractured Reservoirs by Tracer Injection
Authors: Qasem Fuad , Gharbi Ridha B.C. , Mir Muhammed I.
Published: December 2007

There is considerable interest in the petroleum industry to characterize partially fractured reservoirs and to develop an increased understanding of the physics of fluid flow in these types of reservoirs. This is because fractured reservoirs have different behavior and there exist a large number of these reservoirs that are not fully developed. This paper presents a numerical simulation study that was performed to investigate the effect of rock properties on the tracer response in partially fractured reservoirs using a finite difference numerical simulator. These properties include fracture intensity, fracture porosity and matrix permeability. The functional relationships between these parameters and the calculated effective permeabilities are also investigated. Several images, each with different probability of fracture intensity, were generated randomly. Numerical simulations of single-phase tracer transport were then performed in each of the generated fractured models. Results show that the fracture intensity, fracture porosity and matrix permeability have a significant effect on the tracer response in naturally fractured reservoirs. Depending on the reservoir properties, the results also show that the flow in partially fractured reservoirs can be either matrix-dominated or fracture-dominated. The characteristics of each regime and the conditions for its occurrence are presented.
A New Method to Characterize the Size and Shape Dynamics of Asphaltene Deposition Process in CO2 Miscible Flooding
Authors: Fisher Douglas , Yazawa Nintoku , Sarma Hemanta , Girard Marcel , Turta Alex , Huang Haibo
Published: December 2007

The use of miscible solvents in Improved Oil Recovery (IOR) processes requires knowledge of how the solvent will behave over all mixing ratios of oil and solvent. In particular it is important to know: (i) at what solvent concentration the asphaltenes start to precipitate, and (ii) what conditions will cause the particles to flocculate and eventually deposit in the reservoir pore network. In order to study this process we have developed a new method of describing the process of asphaltene precipitation/flocculation/deposition under typical reservoir conditions.

This method uses image analysis to convert the information obtained from a typical sequence of images obtained from a dynamic high pressure mixing system acquired using a Micro-Visual cell and special optics. These images are analyzed and a single number per image is computed. This number is defined as the "Particle Growth Factor" (PGF), which is a compound number that includes information about the size of the particles, the number of particles and their shape.

This new approach shows how PGF increases with respect to solvent concentration. If we use a suitable non-linear model to fit PGF with respect to concentration, we can use the characteristics of the function to predict the onset of precipitation, the point of maximum flocculation, and when deposition is at its maximum. We can then produce a least squares correlation, which relates the concentration of asphaltene precipitation onset to both pressure and temperature, using a 3D polynomial surface.

In the field, this information can then be used to predict production/injection performance and different operational problems related to asphaltene deposition in CO2 miscible injection and also CO2 sequestration process in a depleted oil reservoir.