bluuebunny/crossref_metadata_2025 huggingface dataset:
Effects of Stress on Fracture Properties of Naturally Fractured Reservoirs
Authors: Chacon Abel , Tiab Djebbar
Published: December 2007

This paper analyzes the effect of stress on the rock properties fracture and matrix compressibilities, fracture and matrix porosities, and permeability in naturally fractured reservoirs (NFRs).

In NFRs, fluids are stored inside the matrix pore space and inside the fractures of the rock. The reservoir characterization parameter indicating the volumetric fraction of fluids deposited inside the fractures is the storage capacity ratio, which is function of the fracture and matrix porosity, and fracture and matrix total compressibilities. Due to the difficulty to obtain these values, in reservoir engineering computations such as pressure transient analysis and reservoir simulation, among others, it is generally assumed that the matrix and the fracture total compressibilities are equal. This induces a big uncertainty in the estimation of the storage capacity ratio and leads to a wrong estimation of the volume of fluids inside the fractured rock.

Changes in pore pressure due to production or injection of fluids affect the effective reservoir in-situ stress. The mechanical behavior of the fractured rock and its effects on the rock properties permeability, porosity and compressibility in the matrix and fracture frames are analyzed using the elastic properties bulk modulus and normal compliance of the fracture. These properties can be obtained from petrophysical core analysis or multi-component seismic interpretation, and linked to pressure transient analysis through the storage capacity ratio equation. A step-by-step procedure of the analysis is presented and illustrated with an example for quantifying the effects of changes in effective stress on the fracture and matrix compressibilities.
Economic Modelling of an Oil and Gas Project Involving Carbon Capture and Storage—Snøhvit LNG Field (Barents Sea, Norway)
Authors: Negrescu Matei
Published: December 2007

The Snøhvit LNG project developed by Statoil and partners in Norway, is used as an example to describe how the Carbon Capture and Storage (CCS) component of an oil and gas project can be isolated, modelled and analysed from an economic point of view. The Snøhvit development, due to start production in late 2007, will involve a CCS component from day one. Approximately 700,000 tons of CO2 captured from the liquefaction plant will be reinjected every year in an underground formation offshore. Furthermore there are interesting alternatives for CO2 capture from the on-site power plant and for the use of CO2 for EOR in a nearby oilfield, leading to several future development scenarios for CCS at Snøhvit.

Different development scenarios for CCS are analysed to select the best development option. The economic modelling framework will also be used to assess the impact of the uncertainties on the project economics.

The analysis identifies that a key driver for the profitability of the project is the legislative setting for CCS. The involvement of the government is very important for the viability of the project, which needs a strong incentive, as the current CO2 tax scheme or an emission trading scheme with strict allocation of emission targets. Under such conditions a CCS project such as Snøhvit becomes a win-win situation: economically profitable for the operator and environmentally friendly.

From a broader perspective, addressing the economic and legislative uncertainty currently surrounding CCS projects for the oil and gas industry is crucial because this represents the main limiting factor for the further development of such projects. It is therefore essential that economic modelling tools such as the framework described in the present work become industry standards so as to ensure that projects which could be profitable for both the operator and the environment are not abandoned by pure lack of analysis ability.
Thermodynamically Consistent Analytical Approach for Streamline Simulations of Multicomponent Hydrocarbon Reservoirs
Authors: Podgornova Olga , Myasnikov Artyom , Bratvedt Kyrre , Rykov Yuri , Koldoba Elena , Koldoba Aleksandr
Published: December 2007

One of the most challenging problems for reservoir simulation is the computation of a multicomponent flow of compressible fluids in porous media with mass exchange between phases. In this work, we consider a streamline method for two phase compressible multicomponent flows in hydrocarbon reservoirs. We prove, that even with standard PVT procedures performed at each time step at each spatial point, streamline technology maintain its better scaling ability than traditional finite difference/volume technologies. However, we went further and have treated the thermodynamics in terms of Koldoba & Koldoba approach7. The model allows for receiving phase equilibrium curves and other thermodynamic functions in analytical form, thus it achieves the thermodynamic agreement of system and greatly reduces the required computing resources.
Relative-Permeability Modifiers and Their Use in Acid Stimulation in HP/HT Low-Permeability Carbonate Formations: Offshore Mexico Cases
Authors: Duverney Eduardo Soriano , Robles Fernando , Lopez Antonio Inda , Steffani Octavio
Published: December 2007

Successful acid stimulation requires a method for diverting an acid across the entire hydrocarbon-producing zone. Because most producing wells are not homogeneous and contain sections of varying permeability, being able to completely acidize the interval is a major problem. This paper describes the use of a new low-viscosity system that uses a relative permeability modifier (RPM) that diverts acid from high-permeability zones to lower-permeability zones and inherently reduces formation permeability to water with little effect on hydrocarbon permeability. This system has been used effectively offshore Mexico with success for more than two years. The cases presented in this paper show the first application in a low-permeability carbonate formation where oil production was increased significantly compared to previous traditional acid treatments using conventional diverters.

The other important feature of this work is that the downhole conditions were high-pressure/high-temperature (HPHT). Details from the jobs using this new RPM acid-diversion system will be presented showing pre- and post-job production results.
The Effect of Lateral Anisotrophy on Flood Pattern Dimensions and Orientation
Authors: McElroy Stacy L.
Published: December 2007

This paper compares different flood pattern orientations and dimensions for isotropic and anisotropic reservoirs in order to determine the optimum waterflood pattern in the presence of directional permeability. This was accomplished by simulating the reservoir performance for several patterns with a 5-point black oil simulator. The patterns simulated include the: 1) 5-spot, 2) inverted 9-spot, 3) modified 9-spot (an inverted 9-spot pattern with two producing wells eliminated), and 4) direct line drive.

For simplification, unit mobility ratio and miscible displacement were used to model the displacement of oil by water, although the conclusions are identical for a mobility ratio different from one and an immiscible displacement. Each pattern was tested with the dimensions being both square and elongated (four times the length in one direction). Each of these sets of patterns were simulated as isotropic and anisotropic reservoirs. The patterns were elongated in the direction of and in the direction opposite to the high permeability trend.

Included is a discussion of results of each pattern tested and conclusions as to the optimum waterflood pattern for anisotropic reservoirs. These conclusions may be applied to any reservoirs having directional permeability. These results may be realized with any injection scheme such as CO2 injection, natural gas injection and steam flooding.
An Experimental Investigation of Three-Phase Flow of Water-Oil-Gas Mixtures Through Water-Wet Sandstones
Authors: Saraf Deoki N. , Batycky James P. , Jackson Clive H. , Fisher Douglas B.
Published: December 2007

Three-phase relative permeabilities to water-oil-gas mixtures have been measured both under unsteady-and steady-state conditions through fired Berea sandstone. A computer-based photometric device was used for monitoring fractional flow of displacement fluids. An extension of the Welge-JPN method to three-phase flow was used for the calculation of relative permeabilities from displacement data. Several saturation histories relevant to petroleum reservoir exploitation were examined. Steady-state measurements with saturation histories similar to those in the unsteady-state experiments were made on the same core to enable comparison of the results.

Water relative permeabilities were found to depend only on water saturation and were practically independent of the saturation histories considered. Gas relative permeabilities depended on the total liquid saturation; the components of the liquid being of no concern. They depended strongly, however, on the direction of saturation change of the gas phase.

Oil relative permeabilities seemed to depend on saturations of all the phases present. Although the direction of oil and water saturation change did not influence oil relative permeabilities significantly, the decreasing gas saturation resulted in higher values as compared to those when the gas saturation was increasing. This seems to suggest that trapping of gas facilitates more free movement of oil. Predictions made by the use of Stone's two models yielded lower values of relative permeability to oil when compared to the experimental results, suggesting the inadequacy of these models even for the strongly water-wet rocks used in the present study.

Steady-state measurements of three-phase relative permeability yielded results similar to those obtained by the displacement method for both oil and water. However, owing to a different trapping mechanism, the gas phase relative permeability showed a much weaker dependence on the direction of gas saturation change under steady-state conditions when compared to the displacement process.
Comparison of Methodologies To Evaluate the Risk of Petroleum Fields
Authors: Ligero Eliana L. , Risso Fernanda V. Alves , Schiozer Denis J.
Published: December 2007

A risk analysis process can be applied to several phases of a petroleum field. The methodologies required in the decision-making process depend on the level of uncertainties, which vary according to the field phase. This work is focused on the development phase and the decision process is based on probabilistic procedure to represent all possible scenarios of the reservoir.

The uncertain attributes can be combined through derivative tree or Monte Carlo technique. The risk can be evaluated by the Net Present Value, which depends on the reservoir performance. The reservoir production prediction can be obtained through numerical simulation or response surface. Most of works consider only the application of these procedures and comparisons of these techniques are not well evaluated. The goal of this work is to apply the alternative combinations of these techniques to petroleum fields and compare them to determine the result reliabilities.

The combination of Monte Carlo and numerical simulation is not viable, in some cases, due to the great number of simulations. The attribute combination by derivative tree can be an alternative, but can also yield a high number of simulation runs. Alternatives to speedup the process are to reduce the number of attributes and their discretization levels or substitute the conventional reservoir modeling by faster ones, such as the response surface, which is suited to evaluate the impact of uncertainty on production forecasts.

The contributions of this work are to: (1) to determine if the response surface can substitute the reservoir simulator, (2) to evaluate the capability of the response surface to substitute the reservoir simulator in order to obtain the risk curves, (3) to provide a guide to select an adequate combination of techniques according to the desired precision and (4) to determine if it is possible to reduce the number of simulation runs, maintaining the precision.
Fighting Lead and Zinc Sulphide Scales on a North Sea HP/HT Field
Authors: Orski K. , Grimbert B. , Menezes C. , Quin E.
Published: December 2007

Lead and Zinc sulphides have recently become a concern in some HP/HT gas fields.

The Elgin/Franklin Field (Central Graben North Sea), started production early 2001. The wells produce a condensate-rich gas from the Fulmar and Pentland reservoirs, with initial temperature of 200 degC and pressure of 1100 bar.

Mid-2002, the first Calcium Carbonate obstructions appeared downhole on several wells and resulted in a progressive production decrease.

Moreover, lead and zinc sulphides were identified on well G6. The heavy scaling from its surface-controlled subsurface safety valve (SCSSV) to the Christmas Tree caused the well to be shut-in from end 2004 until an appropriate programme of remediation and prevention was implemented.

Lead and zinc sulphides had not been predicted during the initial scaling studies. While several publications mention these on HP/HT fields, little information is available on downhole inhibitor squeeze.

Scale removal lab studies included dissolution of the recovered scales and corrosion tests. A different fluid package was selected for downhole and SCSSV conditions.

Scale remediation using downhole acid washes proved efficient by increasing wells production.

The upper part of the completion on well G6 was cleared from scales by a coiled tubing operation in mid-2005 and the integrity of the SCSSV was restored.

To prepare for scale prevention, a benchmarking of inhibitors from four suppliers was performed in a third party lab over a period of more than two years. Appropriate equipment was put in place and the methodology was optimised. The tests were conducted in anaerobic conditions with thermally aged chemicals.

Two scale inhibitor squeezes were deployed, although progress is still to be made for "exotic" scale prevention.

This paper presents the Elgin/Franklin scale-control strategy from a thorough fluids selection to the field deployments. Results and optimisation are discussed
Evaluation of a Conventional Steam Drive With Ancillary Materials: North Kern Front Field
Authors: Eson Rod L. , O'Nesky Stephen K.
Published: December 2007

Steam drive projects account for over 64% of all of the United States' Enhanced Oil Recovery (EOR) production, nearly 156,000 BOPD (24,000 m3/d). Even though steam drive is the most successful of all EOR processes, it is not without its problems. Gravity segregation and poor areal and vertical sweep efficiencies have limited recoveries in many heavy oil reservoirs. In many instances the injected steam prematurely breaks through into producing wells creating steam channels. If this steam channeling can be controlled to some degree and the steam is forced to contact more of the reservoir, overall recoveries can be improved. This paper documents efforts under a Department of Energy cost sharing contract to reduce steam channeling in a conventional steam drive using ancillary materials.

A steam foam solution and a steam foam encapsulated in a polymer gel are being introduced in four steam injection patterns in the North Kern Front Field near Bakersfield, California. The ability of the ancillary materials to improve recovery will be determined through injection profiles, chemical tracer surveys, casing vent gas analyses, core and log data, and residual oil saturation data, as well as through temperature and production monitoring.

It has been shown that in-situ steam foams can be used to alter the steam injection profiles to prevent excessive steam channeling. Results after injection of ancillary materials for approximately 18 months indicate that improvements in both the areal and vertical sweep efficiencies have been found in the four treated patterns when compared to the untreated control patterns. Several techniques are still under evaluation to determine the exact amount of incremental oil produced.

Disscussion of production response will be limited to two of the four treated patterns, Witmer B2-3 and Witmer B2-5. A comparison of these two patterns to the Witmer control pattern, Witmer A2-7, indicates approximately 52 B/D (8 mv/d) of incremental oil is being produced as a result of the weekly chemical treatments.
A Numerical Model for Multiphase Flow on Oil Production Wells
Authors: Ferro S. P. , Goldschmit M. B.
Published: December 2007

A numerical model for the analysis of multiphase flow on vertical or slightly inclined wells has been developed. The model calculates flow properties (velocity of each phase, volumetric fraction of each phase, pressure and fluids properties) on gas-oil-water wells as function of depth. Fluids properties are obtained under the assumption of black oil model by means of correlations taken from literature, requiring only petroleum °API and the gas specific gravity as input data.

The model may be applied to simulate both liquid flow and gas-liquid flow. In this case, different flow patterns are taken into account: -bubble, slug, dispersed bubble and annular-depending on flow conditions, which are determined from fluid properties and production rates of oil, gas and water. Flow in tubings consisting of several sections with different diameters and inclinations may also be simulated.

The model was validated by comparisons of measured and calculated the pressure variation along the well Good agreement was found between the numerically predicted pressure drop and measurements taken from different databases from open literature. As a consequence the proposed model proves to be a reliable tool to describe the flow on oil-gas-water wells.

The developed numerical model takes into account the most relevant effects that take place in a production well including multiphase flow, presence of different flow pattern, mass transfer from gaseous to liquid phase and influence of gas-liquid flow pattern on wall friction. Special attention is paid to the velocity profile of each phase along the well. Ishii's model for two-fluid flow is used to prescribe the slip velocity between liquid and gaseous phases and to determine the acceleration term contribution to the pressure gradient. This model is actually being employed for corrosion rate calculations inside production wells.
Wireline Logs and Core Data Integration in Los Molles Formation, Neuquen Basin, Argentina
Authors: Stinco L. P.
Published: December 2007

In Agua del Cajón Block (Neuquen Basin, Argentina), petrophysical data was treated according to deductive and inductive methods in order to get the most from both approaches. Deductive methods comprise those methodologies that seek to differentiate the data by the computation of a set of component proportions whose identification is linked with wireline log data by a set of response equations. The model is built considering the number of components and the number of variables (data curves). Normally, measures to detect mismatches and gross errors are included in the techniques, although mathematical consistency is not a guarantee of geological accuracy. This situation is well represented by standard log analysis. On the contrary, inductive methods establish their classes or transformations based on the data set and do not depend on any predetermined correlation among the components. These methods tend to isolate distinctive patterns and to derive classifications or new variables that can be interpreted with a physical meaning. Cluster analysis is one example of these types of methodologies. In this study, wireline logs (spontaneous potential, gamma ray, shallow-medium and deep resistivities, neutron, density, sonic, photoelectric factor, and microrresistivity images) were calibrated according to the lithological variations – facies- described in cores taken from the reservoirs developed within Los Molles Formation. These facies which comprised crudely bedded gravel with imbrication (Gm), medium to coarse, even pebbly sand with planar crossbeds (Sp), very fine to very coarse sand with horizontal lamination (Sh) and massive mud-silt (Fm), were linked with electrofacies using multivariate analysis, particularly cluster analysis. The first two facies are the actual reservoirs targets within the field. After the analysis of ten wells within the field, a more thorough understanding of the petrophysical properties and a deeper understanding of the dynamic responses of the reservoirs was achieved.
Improved ASP Design Using Organic Compound-Surfactant-Polymer (OCSP) for La Salina Field, Maracaibo Lake
Authors: Guerra E. , Valero E. , Rodriquez D. , Gutierrez L. , Castillo M. , Espinoza J. , Granja G.
Published: December 2007

In design and implementation of Alkali Surfactant Polymer (ASP) formulation for IOR processes, the inorganic alkali component acts as sacrificing agent avoiding the surfactant adsorption and decreasing the IFT. Nevertheless, as a part of this process there are some potential problems to be considered previously and during ASP injection processes such as: the ASP injection water should be softened to prevent scale formation that produces higher costs for water treatment, possible tubing corrosion problems and possible viscosity reduction. The effect of organic alkali on IFT, adsorption and viscosity has been previously focussed on comparing to the conventional inorganic alkali in these formulations. In those investigations, it was founded that organic alkalis are compatible with unsoftened waters and the rest of ASP slug components, reduce adsorption, minimize the surface equipment and the formation damage what reduces initial investment costs and greater project profitability.

The objective of this study is to show the advantages and outcomes in applying an improved design of the current ASP formulation for the pilot project La Salina Field Maracaibo Lake, using an organic compound-surfactant-polymer (OCSP) formulation, which uses an organic compound as substitute for traditional inorganic alkali. In fact, fluid-fluid and rock-fluid compatibility laboratory tests, new chemical components concentrations, phase behavior study, IFT screening and porous media evaluations (adsorption and recovery factors) were performed in laboratory in berea cores. Linear corefloods displacements for La Salina LL-03 let to obtain the OCSP flood recovery and additional OOIP estimated of 22.2%. Finally, these results confirm the technical advantages of applying an optimized formulation using an organic agent for this field.
Correction of Bound and Free Fluid Volumes in the Timur-Coates Permeability Equation for the Presence of Heavy Oil—A Case Study From the Golfo San Jorge Basin, Argentina
Authors: Gómez Hugo , Stinco Luis , Nawratil Alejandro , Lopetrone Javier , Romero Pedro , Saavedra Benito
Published: December 2007

In the Golfo San Jorge basin, Argentina, the Timur-Coates permeability index obtained from the T2 distributions is considered as a good indicator of reservoir quality and has been used as a very important variable for production forecast. However, when heavy oil is present, having a relaxation time below the standard free fluid-bound fluid cut-off of 33 ms, it is conventionally counted as part of the bound fluid, independently of its mobility. For this reason, in case of movable heavy oil, the standard Timur-Coates permeability index using 33 ms tends to be always pessimistic, in eventual disagreement with other reservoir quality indicators as the SP curve, depositional environment, cuttings and production data.

In order to perform a correction of the permeability index for the presence of heavy oil, two layers of one well from the Diadema field, with a complete set of SP, Resistivity, MREX and production data was selected and evaluated using 2DNMR (T2intrinsic - Diffusion) maps, which uses the diffusivity contrast for discriminating between capillary bound water and heavy oil, within the bound fluid window (BVI). The clay bound water (CBW) cut off has been chosen to be 6 ms.

The results show that the corrected Timur-Coates permeability can increase by an order of magnitude in the tested zone of the reservoir layers, but can become even higher within the whole layers, which is a reasonable estimation for the corresponding channel depositional environment. The production data also support the interpretation, indicating that the NMR rock quality estimation can be performed more accurately even in the presence of heavy oil. The corrected Timur-Coates permeability values can be used in a future update for forecasting well production.
Heavy-Crude-Oil Upgrading With Transition Metals
Authors: Nares H. R. , Schacht-Hernández P. , Ramírez-Garnica M. A. , Cabrera-Reyes M. C. , Noé-Valencia L.
Published: December 2007

In this paper are discussed the effects of some metallic oxides used to upgrade the heavy crude oil properties. The underlying objective is to increase the mobility of the oil in the reservoir by reducing viscosity and improving the oil quality using alumina supported transition metals and liquid phase transition metals catalysts (derived from either acetylacetonate or alkylhexanoate compounds), both homogeneously mixed with heavy crude oil. This heavy crude oil upgrading is based on the decrement of the asphaltenes, resins, and sulfur contents, and the increment of its API gravity, and strong reduction of viscosity.

In the present work the heavy crude oil from the Golf of Mexico was studied. The API gravity was increased from 12.5 to 21-26, the kinematics viscosity was decreased from 18,130 to 100-8 cSt (at 298 K), the asphaltene content was reduced from 26 to 7 wt%, the sulfur was removed in the range of 30 to 60 wt%, and the distillable fraction was increased between 20 to 30 wt%, and determinated by Simulated Distillation and True Boiling Point (TBP).
Treatment of Wellbore Storage Effects in the Analysis of Pressure Buildup and Drawdown Tests
Authors: Lo Tak Sing , Youngren Gary K.
Published: December 2007

In this paper, we propose a new method for detecting the beginning of the useable portion of a Horner plot. The method is based on asymptotic solutions of the well-bore material balance in a form used in numerical simulators. They show that the Extent of Well-Bore Dominance, EWBD, which measure the effect of well-bore storage on pressure drawdown and buildup test results, is a function of well-bore storage capacity, the formation producing capacity (related to the productivity index), the bottom-hole pressure, and its time rate of change. EWBD always decreases to zero as the reservoir response assumes control of the bottom-hole pressure. This is true for any size well-bore, and is unaffected by the complicated flow history during the opening and closing of the valve. Here, the theoretical basis of EWBD is developed, followed by a description of its implementation in automated Horner analysis computer programs. Five examples are presented which demonstrate that the automated Horner analysis program can perform a classical Horner analysis rapidly, accurately, and reliably.
Evolutionary Optimization of Smart-Wells Control under Technical Uncertainties
Authors: Almeida Luciana Faletti , Túpac Yvan J. , Lazo Lazo Juan G. , Pacheco Marco Aurélio , Vellasco Marley M. B. R.
Published: December 2007

This work presents a system, based on Evolutionary Algorithms, capable of optimizing the controlling process of intelligent wells technology present in Intelligent Fields. The control refers to the opening and shutting operation of valves in these wells. A proactive controlling strategy to find a configuration of opening and shutting valves was assumed. It anticipates and maximizes the oil recuperation, delays the water cut on producer wells, and reduces the quantity of produced water, maximizing the wells life. As a result, the obtained configuration promotes the increasing of NPV (Net Present Value). The use of control strategies to benefit the completion identifies the field as intelligent. The proposed representation can formulate a controlling strategy for all valves, for any desired time interval. To improve the decision making for using or not using smart wells, the fault risk of the control device existing in the intelligent completions was considered into optimization. For this purpose, the system applies Monte Carlo simulation together with some simulation techniques for convergence acceleration and uncertainties representation by probability distributions. Even considering the existence of uncertainties into valves operation, the results obtained in the tests reveal significant gains by using the intelligent completion on the field such as: increasing the recuperation factor of the field, reducing the water inflow and increasing the longevity of the field. For all valves representations, improvements were achieved when compared with the case without valves. The conception and implementation of an intelligent system, capable of supporting the development and management of intelligent petroleum fields, builds up an important advantage for the spreading of intelligent field technology. The results obtained in this work demonstrate that the intelligent control of valves can become a competitive difference in the strategy of hydro-carbon production.
Miscible EOR Processes: Existence of Elliptic Regions in Gasflood Modeling
Authors: Dutra T. A. , Pires A. P. , Bedrikovetsky P. G.
Published: December 2007

Enhanced Oil Recovery (EOR) methods include injection of different fluids into reservoirs to improve oil displacement. Analytical models for 1-D displacement of oil by gas have been developed during the last 15 years. It was observed from semi-analytical and numerical experiments that several thermodynamic features of the process are not dependent on transport properties. The model for one-dimensional displacement of oil by miscible fluids is analyzed in this paper. The main result is the splitting of thermodynamical and hydrodynamical parts in the EOR mathematical model. The introduction of a potential associated with one of the conservation laws and its use as an independent variable reduces the number of equations. The reduced auxiliary system contains just thermodynamical (equilibrium fractions of each phase, sorption isotherms) variables and the lifting equation contains just hydrodynamical (phases relative permeabilities and viscosities) parameters while the initial EOR model contains both thermodynamical and hydrodynamical functions. So, the problem of EOR displacement was divided into two independent problems: one thermodynamical and one hydrodynamical. Therefore, phase transitions occurring during displacement are determined by the auxiliary system, i.e. they are independent of hydrodynamic properties of fluids and rock. For example, the minimum miscibility pressure (MMP) is independent of relative permeabilities and phases viscosities. The new technique developed permits splitting for both self-similar continuous injection problems and for non-self-similar slug injection problems. Splitting significantly reduces amount of calculations for sensitivity study with respect to transport properties: auxiliary thermodynamic problem may be solved once for given reservoir and injected compositions; variation of relative permeabilities and viscosities should be performed just in the solution of one transport equation. In this paper, different analytical solutions for 4-component gas injection problems are analysed. It was considered the injection of nitrogen and hydrocarbon gases into a three-component liquid reservoir fluid. The eigenvalues of the system are related to the propagation velocity of each component in porous media. The existence of elliptic regions (complex eigenvalues) is well known in three-phase flow, but for the first time it is shown that this feature may also occur in two-phase flow. The independence of compositional dynamics on transport properties can be used for testing numerical compositional simulators. If the mobility ratio is close to one, this model may be applied in the development of streamlines simulators.
Tracer Experiments in Eastern Devonian Shale
Authors: Cook Thomas L. , Brown Lee F. , Meadows Wayne R.
Published: December 2007

For the purpose of characterizing the properties of the Eastern Devonian gas shale, a seven-day tracer experiment was carried out in August of 1981 by the Los Alamos National Laboratory as part of the DOE's Offset-Well Test. Two wells had been drilled in a Columbia Gas Company field in southeastern Ohio, each with a downhole separation of approximately 120 feet from an existing production well. The isoceles triangle formed by the three wells had an apex angle of approximately 110 degrees. About 56,000 SCF of nitrogen were injected into a producing zone located at a depth of 3300 feet in one of the wells. Gas was then produced from the various wells at different rates and pressures for the duration of the test. Both pressure and gas composition in the three wells were monitored thoughout the test.
The Methane Content of San Juan Basin Coal: Implications for Coalbed Methane Resource Assessments
Authors: Smith Douglas M. , Williams Frank L. , Sato Tet , Lee Young H. , Malone Rodney D.
Published: December 2007

The potential methane resource for the Fruitland coal formation of the San Juan Basin of northwest New Mexico has been analyzed. Gas contents ranging from 1 to 8 cm3/g were found for 33 samples from 14 wells which were at depths from 300 to 1000 m. Gas contents were determined using the "chip desorption" method. This method allows the use of drill cuttings obtained from conventional drilling operations as the coal seam is penetrated. The use of core samples which is required in the Bureau of Mines method is eliminated.

Contrary to past basin studies which used a limited number of data points, no direct correlation between depth and in-place gas content was evident. In order to explain the lack of a depth/gas content relationship, the physical properties of the coal relevant to gas adsorption were studied. Surface area measurements using low-pressure CO2, CH4, and neopentane adsorption have been conducted. Differences in adsorption capacity between the various samples is small and cannot explain the order of magnitude variation in gas content. In summary, it appears that local geological factors (i.e., the nature of the over and underburden) play a much larger role in the in-place gas content of coal than previously thought. This implies that a large number of data points is required to accurately characterize the total quantity of coalbed methane in a particular basin.
Evaluation of Different Models for Injectivity Decline Prediction
Authors: Furtado C. J. A. , Souza A. L. S. , Araujo C. H. V.
Published: December 2007

There are several kinds of injectivity decline models, going from phenomenologicals ones, that consider the suspended solid mass balance and its damage on well and reservoir, through empirical models based on the experience with a previous field or even historical data. This article presents an evaluation of three differents models: –Phenomenological model: considering mass balance, internal and external (cake) damage and mobility effects when water is injected above the oil-water contact;–Cake properties prediction coupled with flow simulator and;–Empirical model based on previous Perkins and Gonzalez work.

In this work, we compare results from these models and adjust them to fit historical data from injectors wells. Using literature date, we have also estimate parameters from all models and use them to predict the same well behaviour.
Tight Sands: Rapid Mapping From a Computerized Data Base of Well Completions
Authors: Hohn Michael Ed. , Behling Mary C. , Avary Katharine Lee , Patchen Douglas G.
Published: December 2007

Criteria for designating tight formations according to Federal Energy Regulatory Commission Order 99 include limits on maximum permeability and rates of natural production versus depth. Requests for such tight formation designation are to be accompanied by locations of all wells producing from that formation or by a listing of all producing wells.

The role of the West Virginia Geological and Economic Survey in this State's recent successful submittal to the Federal Energy Regulatory Commission was that of providing the necessary computer-generated maps and listings of well documentation for the proposal for Fayette and Raleigh Counties. Similar work for most of West Virginia is in progress. Using a computerized database containing information from drillers' logs, penetration and production maps were plotted showing well locations, permit numbers, and well type (gas, oil, combination, or dry/miscellaneous) for specific pay sands. Precision of the maps depends ultimately upon the quality of the data submitted on the drillers' logs.

Current to within the past 3 to 6 months, the computerized database can be accessed through request-specific utility programs which prepare working files for the SURFACE II mapping package. The maps thus produced expedited definition of both scattered and concentrated areas of production and areas of dry penetrations; associated listings supplied the necessary well documentation including natural open flow rates. Rapid delivery of these maps and reports illustrates the value of maintaining detailed, computerized files on well completions. (Permission to publish is granted by the Director and State Geologist, West Virginia Geological and Economic Survey.)
New Downhole Fluid Analysis (DFA) Technologies Supporting Improved Reservoir Management
Authors: Cañas Jesús A. , Freitas Evie , Andrews A. Ballard , Mullins Oliver C. , Colacelli Santiago E.
Published: December 2007

This paper describes a new Downhole Fluid Analysis technology (DFA) being implemented in Latin America for improved reservoir management. DFA is a unique process in fluid characterization for improving fluid sampling, reservoir compartmentalization evaluation and support flow assurance analysis. It combines known and new fluid identification sensors, which allow real time monitoring of a wide range of parameters as GOR, fluorescence, apparent density, fluid composition (CH4, C2, C3-C5, C6+, CO2), free gas and liquid phases detection, saturation pressure, as well WBM & OBM filtrate differentiation and pH, which is key for real time contamination monitoring at the well site with the objective of representative sampling and reservoir compartmentalization analysis. This process is not limited to light fluid evaluation or sandstones.

The combination of DFA Fluid Mapping with pressure measurements has shown to be very effective for compartmentalization characterization. The ability of thin barriers to hold off large depletion pressures has been established, as the gradual variation of hydrocarbon quality in biodegraded oils. In addition, heavy oils can show large compositional variation due to variations in source rock charging but without fluid mixing [1].

Using this method we present field DFA data acquisitions and integrate into numerical simulation modeling to conceptually evaluate the impact of fluid composition / properties gradation and compartmentalization in the productivity of some Latin America reservoirs.
NMR Logging Tool Development: Laboratory Studies of Tight Gas Sands and Artificial Porous Material
Authors: Brown Joseph A. , Brown Lee F. , Jackson Jasper A. , Milewski John V. , Travis Bryan J.
Published: December 2007

We report proton. longitudinal relaxation (T1) measurements on water-saturated samples of Western Tight Sas Sand Core and artifioal porous materials. The artificial samples, with well-characterized and nearly uniform pore structure, serve as a calibration standard for preliminary-efforts at inverting the Nuclear Magnetic Resonance relaxation data on the Gas Sand core samples to obtain a distribution of pore surface-to-volume ratios. The distributions obtained show good to excellent agreement with those obtained by mercury porosimetry on the same samples. Various possible effects are discussed, which could account for the discrepancies observed.
The Effects of Mining and Methane Production Activities on Dynamic Reservoir Conditions
Authors: Boyer Charles M. , Dobscha Francis X. , Schwerer Fred C. , Stubbs Paul B.
Published: December 2007

Six unstimulated vertical wells were drilled into the Blue Creek coalbed to measure the changes that occur in coalbed reservoir characteristics because of mining activity. Results indicate that an advancing mine face affects only a small area of the coalbed ahead of the face. If the mine face remains stationary, the coalbed area affected by the face increases with time.
Multiple Zone Coal Degasification Potential in the Warrior Coal Field of Alabama
Authors: Graves Stanley L. , Patton Abner F. , Beavers Wendell M.
Published: December 2007

The upper Pottsville Formation in the Warrior Coal Field of Alabama has seven recognized groups of bituminous coal seams. Three of these groups, the Pratt, Mary Lee, and Black Creek consist of seams containing commercially significant quantities of methane. Each group has several seams within a vertical interval that, in many areas, can be collectively stimulated. In parts of the Warrior Coal Field, where all three groups can be penetrated in one vertical borehole, the potential production from multiple zone completion wells can result in commercially profitable wells. Various open hole and through the casing completion procedures are being applied resulting in successful methane production from these multiple zone coal gas wells.
Production and Utilization of Coalbed Methane Gas in Island Creek Coal Company Mines
Authors: Von Schonfeldt Hilmer , Pothini B. Rao , Aul George N. , Henderson Roger L.
Published: December 2007

Occidental Research Corporation has for the past five years been actively engaged in a research program of draining methane gas from the Pocahontas #3 coal seam. This work is being conducted in Island Creek Coal Company's deep mines in the Virginia Pocahontas Division. The technique consists of drilling long horizontal inseam holes in advance of mining. The initial objective of the program was to reduce methane emissions in mine workings in order to improve mine safety and productivity. As the research program evolved, potential for commercial scale production and utilization of the gas resource became apparent. Current research activities include production and capturing of the gas and utilization at the mine plant for drying the coal. To date 27 horizontal holes have been drilled in three mines for an aggregate depth of over 6,400 meters (21,000 feet). The longest hole is 835 meters (2,740 feet). Over 18.4 million cubic meters (650 MMCF) of pipeline quality gas has been drained and transported safely to the surface through a network of underground pipelines. Coal dryers have been retrofitted with gas burners to replace #2 fuel oil and pulverized coal for drying coal.
A Step by Step Approach to Hydraulic Fracture Treatment Design, Implementation, and Analysis for Tight Gas Sands
Authors: Ahmed Usman , Schatz John F. , Abou-Sayed Ahmed S. , Jones Arfon H.
Published: December 2007

A synthesis of treatment design parameters, treatment procedures in the field, quality control, and analysis of created fracture parameters is essential to improve and optimize hydraulic fracture treatments in a particular field. This paper provides a step-by-step approach to treatment design optimization that combines laboratory, field and analytical efforts. The laboratory program includes measurements of porosity, absolute and relative permeability, capillary pressure, elastic moduli, matrix permeability and proppant bed sensitivity to fluid (reservoir and treatment) all at simulated in-situ conditions and appropriate petrographic study. The field test program involves in-situ stress measurements (mini-fracs in the pay and surrounding formations), fracture orientation determination and transient pressure tests. Successful implementation of the optimized design is then carried out by monitoring of flow rate and bottom hole pressure during the job and change of design parameters as necessary to tailor the fracture geometry. This must be coordinated with a quality control program for both the equipment and materials used in the job. A brief review of the state-of-the-art of transient pressure analyses of fractured wells is also included in the paper to inform the practicing engineer of the advantages, disadvantages and limitations of each technique. Finally, a field example is presented that illustrates the step-by-step approach. Designed and created fracture parameters are critically compared to demonstrate the effectiveness of the procedure and show how such information can be used to further improve results.

We gratefully acknowledge the Gas Research Institute (GRI) and the U.S. Department of Energy, which have funded some of the work presented here.
The Occurrence and Magnitude of Methane — Hydrate Accumulations
Authors: Zielinski Ronald E. , Mclver Richard D.
Published: December 2007

Solid, ice-like mixtures of natural gas and water have been found immobilized in rocks beneath the permafrost in Arctic basins, and in muds under deep water along the continental margins of the Americas. While these unusual compounds have been known and studied by chemists for over a century and a half, and by gas transmission engineers for the past fifty years, the discovery of natural occurrences came as a surprise to earth scientists.

Hydrates of methane gas are stable at temperatures above the freezing point of water if the pressures exceed about 400 psi (2.8 MPa). Therefore, natural gas at near-saturation volumes would combine with water to form a solid in areas of low temperature and moderate-to-high pressures, eg., in sediments immediately beneath thick permafrost, or immediately beneath deep (ca 300 m) water. The structure of hydrates -- a crystalline network of interconnected water molecules, the interstices of which contain single molecules of gas -- is such that there are almost six water molecules for each gas molecule combined into the crystal.

Hydrates are solid; therefore they have the potential of immobilizing large quantities of both water and gas in favorable environments. These solid masses will act as barriers to normal fluid movement through the host sediments, and may even form seals and traps that will trap free gas where the structure and stratigraphy of the rocks themselves would not. Moreover, at about 300 meters, a unit volume of reservoir under permafrost can contain six times as much gas in the hydrate form as in the free gas form. This enrichment factor decreases with depth, reaching parity at about 2000 meters, but is an important consideration in calculating possible gas reserves in Arctic regions.

Because such large areas of sedimentary basins of the globe are underlain by permafrost or are covered by water (along the continental margins), the volumes of gas locked in hydrate "reservoirs" may be enormous. For example, based on Soviet estimates of hydrated reserves in Siberia, the shallow reservoirs under the permafrost of North America would contain 200 trillion cubic feet (TCF), or 5.7 × 1012m3, of such gas. The muds under the deep water along the continental margins of North America could contain almost 20,000 TCF, or 5.7 × 1014m3, of gas, but probably only a small fraction, eg., 200 TCF (5.7 × 1012mi, in rocks porous enough to be considered reservoir rocks.

None of this gas is recoverable with present technology. However, the very magnitude of the resource is so large that naturally occurring hydrates should be the object of continuing study and research.