bluuebunny/crossref_metadata_2025_split huggingface dataset:
Experimental and Statistical Analysis of Shaly-Sand Evaluation Using CEC-Dependent Parameters
Authors: Kurniawan B. , White C. D. , Bassiouni Z. 
Published: December 2007

Abstract
A new CEC shaly sand model incorporates two cementation exponents to represent the tortuosity of two distinct conductive paths in the free- and clay-bound-water of shaly sandstone reservoirs. The validity of the model was experimentally tested. Laboratory resistivity measurements were performed on three rock types, clean sand, shaly sand and pure shale with varying water salinity. The cementation exponents were determined from clean and pure shale samples and used in the calculation of shaly sand conductivity. The most critical case of low water salinity shaly sands received particular attention.
Monte Carlo simulation evaluated the uncertainty of water saturation estimates, assuming both correlated and uncorrelated conductivity and porosity. Correlation structure was preserved using the Cholesky factor of the parameter covariance matrix. The uncorrelated simulation yielded sensitivity estimates that were statistically insignificant, whereas the correlated analysis revealed a strong sensitivity of water saturation to rock conductivity. Because parameters such as rock conductivity and porosity are commonly strongly correlated, naive uncorrelated Monte Carlo simulation may understate the sensitivity of water saturation to rock conductivity (in this case, by a factor of almost six).
The new model substantially reduces the estimation error of conductivity of low salinity shaly sand samples (by 10 to 15 percent) compared to a single cementation exponent model. The calculated water saturation was validated with production and special core analysis data in a zone with low formation water salinity. The validity of the model was also tested using field data. The water saturation estimated for actual field cases were more representative of the hydrocarbon potential in the subject reservoirs derived from production and special core analysis data.
Composite-Fracturing Plug Reduces Cycle-Time in a Coalbed Methane Project
Authors: Rodvelt G. D. , Oestreich R. G. 
Published: December 2007

Abstract
Shallow coalbed methane (CBM) projects can have multiple pay zones available for completion. Cased-hole completions allow zonal isolation to direct treatments, but re-establishing a connection to a coalseam through drilling and cementing damage may require high breakdown pressures even with an acid spearhead. Isolating individual zones to help ensure completion effectiveness is paramount to a successful completion.
This paper details the use of composite epoxy-glass fracturing plugs to reduce time to complete, drill out, and clean up wells drilled in the Southern Illinois Basin (SIB) project. Over 80 wells have been completed in multiple stages using as many as three composite frac plugs to isolate four coals. Accurate placement of plugs by electric line to allow staging as close as 10 ft was accomplished without communication. These four-stage frac completions were accomplished in less than 8 hours before flowing back frac fluids from all zones. Less than a single day was required to drill out all the plugs, go to bottom, circulate clean, and prepare the wells to begin pumping. The authors compare this technique with the cost and time required to do completions with alternative isolation methods.
Petrophysical Parameters that Govern Hydrocarbon Production from a Low-Permeability Carbonate Formation at the Wattenberg Field in the Denver-Julesburg Basin
Authors: Yang Yuanhai , O'Connell Wally , Birmingham Thomas 
Published: December 2007

Abstract
In carbonate reservoirs, it has been commonly reported that natural fracture is the primary factor that governing hydrocarbon production. By a renewed investigation into the Niobrara low permeability carbonate at the Wattenberg field in the Denver-Julesburg basin (DJ), the authors have observed a series of petrophysical factors that can be reflected by well logs affect well performance. The conventional well logs have been used to calculated or estimated these petrophysical parameters, which include irreducible water saturation calculated by the resistivity and porosity; solution gas oil ratio computed from the neutron and density; pore structure connectivity reflected by the spontaneous potential; the proximity to faults inferred from the density correction log; and original high reservoir pressure determined from changes in resistivity and neutron of overlying shale.
CO2 Restimulation in the Michigan Basin: A Second Chance for the Prairie Du Chien
Authors: Edwards J. T. , Crafton J. W. 
Published: December 2007

Abstract
The Michigan Basin is widely viewed as having only mature reservoirs with limited availability for new treatment designs. The latest re-stimulation program using CO2 might give rise to the opportunity of enhanced production in Michigan as well as benefit new completions.
The Prairie Du Chien (a.k.a. PDC) is a sandstone formation with depths that vary from 8,000 to 11,000 feet and formation thicknesses ranging from 50 to 200 feet. Stimulation treatment designs over the past two decades since the PDC's initial drilling have been marked by vast differences in natural gas production numbers from wells within the same field. Re-stimulation treatments have included cross-linked fluid or nitrogen foam, providing mixed success rates. Problems such as excessive surface treating pressure, limited down-hole sand concentration, early screen outs, and water retention have been experienced in these stimulations. Many existing wells within established PDC fields have declining production numbers despite reasonable reservoir pressure still present.
Formation characteristics and well history will be detailed to shed more light on the current wells and re-stimulations taking place in the PDC. The advantages of the CO2 treatment design marked with increased fluid recovery capabilities by gas assist along with the hydrostatic advantages will be expanded upon. Treatment design details with pressure response along with production results from the first set of wells will be included.
This paper will expand re-stimulation ideas as well as spur a desire for further investigation into the use of CO2 in the Prairie Du Chien. It also hopes to change the perception of the Michigan Basin to one of a viable, rediscovered source of natural gas in the ever tightening world supply.
Modeling Incremental Swelling of Coal Matrix with CO2 Injection in Coalbed Methane Reservoirs
Authors: Mitra A. , Harpalani S. 
Published: December 2007

Abstract
In the enhanced coalbed methane production (ECBM) option involving injection of CO2 in a coal-gas reservoir, the injected CO2 induces incremental swelling of the coal matrix. This is believed to result in a significant reduction in coal permeability, and thus the CO2 injectivity. This paper discusses the results of a study where swelling of the coal matrix was first measured with injection of methane and CO2. This was followed by injecting CO2 in the methane saturated sample, and measuring the incremental swelling for increasing CO2 concentration. The measured swelling with individual gases was then used to model the incremental swelling when CO2 is injected in a CBM reservoir.
The experimental results showed that the amount of swelling produced by CO2 is more than three times that produced by methane. The single-gas swelling data was fitted to a model based on the Langmuir Sorption Theory, and the agreement between the modeled and experimental data was excellent. Finally, the Extended Langmuir (EL) Theory was used to compute the incremental swelling for increasing concentration of CO2. However, the measured and modeled incremental swelling with increasing concentration of CO2 did not match very well. These results are in agreement with the reported finding that the EL Theory fails to accurately predict the sorption behavior of methane/CO2 mixtures. However, the technique serves as a means to estimate incremental swelling until improved methodology is developed to do so.
Integrated Uncertainty Assessment for Unconventional Gas Reservoir Project Development
Authors: Devegowda Deepak , Gao Hui 
Published: December 2007

Abstract
Meeting the gas demand-supply imbalance is crucial in addressing energy requirements for the future. An increasing percentage of the supply of gas will be sourced from unconventional gas reservoirs, for instance, tight sands/shales and coal bed methane reservoirs. However, while unconventional resources contribute an ever increasing fraction of the total gas supply, an integrated analysis and characterization of these reservoirs is often difficult owing to uncertainties associated with various parameters in reservoir and geologic description. Moreover, the high cost of data acquisition limits the amount of information available to build reservoir models.
The main goal of this paper is to provide a methodology for integrated assessment of the petrophysical, geologic and reservoir parameter uncertainties to provide decision makers a rational basis for managing uncertainties leading to improved decisions and resource management. The workflow involves identifying key parameters influencing uncertainties in recovery predictions through an Experimental Design/Response Surface methodology. The need to do a global sensitivity analysis motivates the workflow presented in our study.
The relevant parameters are used to build an emulator or an analog of the reservoir which is then used to rapidly provide performance predictions, taking into account the uncertainties associated with the parameters. The entire framework is applied to a case study to illustrate the cost and time benefits of such an approach. The significant contribution of such an analysis is identifying the effects on reservoir performance due to uncertainties associated with characterizing the reservoir leading to an informed and rational decision making process with significant cost savings and a reduction in computational effort.
Understanding the Effects of Drilling Parameters on Hole Cleaning in Horizontal and Deviated Wellbores Using Computational Fluid Dynamics
Authors: Bilgesu H. I. , Mishra N. , Ameri S. 
Published: December 2007

Abstract
Increased demand for energy resulted in the expansion of drilling activities worldwide. Any improvement in terms of well planning and drilling operation can result in significant savings for the operator. A good plan includes all information from offset wells as well as sound engineering principles and it relies on subsurface characteristics and operating conditions. While formation properties are not controlled by drilling, the operational parameters can be modified to improve the drilling operation on a real time basis. Thus it is important to study the operational factors affecting the performance of a rig. Particularly, understanding the parameters that control wellbore cleaning is beneficial in both horizontal and deviated wells.
In this study, a section of casing-drill pipe annulus section was simulated using Computational Fluid Dynamics (CFD) to determine the effects of different parameters such as fluid velocity, cutting size, rate of penetration, drill pipe rotation and inclination angle in deviated wells. The simulations were conducted at steady state and the results for maximum cutting concentrations in the annulus were analyzed. Formation of cutting beds is noticed near the entry section of the annulus and the transport of the cuttings in the annular section occurred in the form of stratified flow. Fluid flow rate, angle of inclination and rate of penetration have a major impact on cutting concentrations and proper prediction of these parameters are important to avoid formation of cutting beds. It is also noted that drillpipe rotation can enhance cutting transport but it generally has a greater effect on smaller sized particles.
Using Wireline Formation Evaluation Tools To Characterize Coalbed Methane Formations
Authors: Schlachter Greg 
Published: December 2007

Abstract
Wireline formation evaluation tools have been used for over 50 years in conventional formations to acquire formation pressures, permeability, fluid samples and many other reservoir characteristics. These same wireline tools have now been used successfully to characterize coal bed methane (CBM) formations in Alberta, Canada.
Field case studies indicated that conventional pressure transient analysis can be used to interpret CBM wireline formation pressure draw down and build up transients. Downhole optical tools were used during pump out to predict formation fluids in place and determine in situ critical desorption pressures.
This method of formation characterization offers a potentially superior and more complete method of acquiring CBM formation properties than more traditional injection fall off tests. Ambiguities caused by fall off testing can be caused by inflation of coal cleats and fractures, multi-phase permeability and well bore storage.
Formation pressures, permeabilities, in situ critical desorption pressure and formation fluid type are important reservoir properties in CBM plays as in any hydrocarbon bearing formation. Traditional methods of injection fall off data acquisition may be cost effective but difficulties in data quality and interpretation may not justify the initial cost savings.
CO2 EOR From a North Michigan Silurian Reef
Authors: Toelle Brian , Pekot Larry , Mannes R. G. 
Published: December 2007

Abstract
The Charlton 30/31 field, located in the northern reef trend of the Michigan Basin was developed within the stratigraphie unit historically referred to as the Niagaran Brown. The field covers 300 acres with a structural closure of approximately 300 feet and produced 2.6 million Bbl. of oil during its primary production. A total of 6 wells were drilled during the 1970′s to produce the field. This reservoir is a low porosity, low permeability limestone matrix with irregular dolomitized intervals of higher porosity and permeability. Core Energy selected this field for enhanced oil recovery (EOR) using CO2. The source of the CO2 is a nearby natural gas processing plant which removes the CO2 from the produced gas stream of local Antrim Shale formation production in order to meet pipeline quality specifications.
To monitor the flooding of this reef a full field study is being conducted which includes earth model construction, reservoir simulation with history matching and the acquisition of a 4D seismic survey. This study is being funded by the US Department of Energy and the first 3D survey has been acquired. Basic and advanced geophysical analyses were performed on this initial 3D survey. These included wavelet extraction, well to seismic tie generation, horizon interpretation, seismic variance analysis and investigations into a number of other seismic attributes. The results of this interpretation along with the well data were used in static model construction.
Reservoir simulation was performed using this static model and a 25-year production history. During preparation of the field for injection, it was discovered that the reservoir had been an inadvertent dump-flood with water from the overlying Dundee formation, entering the reef through corroded well casings. This significantly complicated the forward reservoir simulation that was used to predict how the CO2 would flood through this reservoir.
Injection of Seawater and Mixtures With Produced Water into North Sea Chalk Formation: Impact on Wettability, Scale Formation and Rock Mechanics Caused by Fluid-Rock Interaction
Authors: Puntervold Tina , Austad Tor 
Published: December 2007

Abstract
Seawater has been injected into high temperature and natural fractured North Sea chalk reservoirs to improve oil recovery with great success. Previous studies have shown that seawater will improve the water wetness and cause enhanced compaction of the matrix. The composition of the produced water will be quite similar to initial formation water at the start of the water injection. The formation water contains various amounts of divalent cations like Mg2+, Ca2+, Sr2+, and Ba2+. Later on, the composition will change due to the interaction between seawater and the chalk formation and some mixing with formation water. The fluid rock interaction will involve dissolution of CaCO3, substitution of Ca2+ by Mg2+ at the chalk surface, precipitation of CaSO4, SrSO4 and BaSO4 depending on the reservoir temperature. Because of environmental reasons, it is desirable to re-inject produced water together with seawater. In the forthcoming research, we will study experimentally the effect of this re-injection on oil recovery and chalk compaction by using mixtures of produced water and seawater as injection fluid. Based on model studies using the OLI-software package, the compatibility of mixtures of produced water and seawater has been studied at different temperatures by looking at the precipitation of CaSO4, SrSO4 and BaSO4. Also the impact of changes in the concentrations of Ca2+ and Mg2+ due to surface substitution is modelled. The results are discussed in terms of possible scale formation in the producer and injector. In addition, actual chemical equilibrium reactions in the chalk matrix are discussed in relation to variation in temperature during continuous injection of seawater. Special focus is made on wettability modification, irreversible thermodynamics, and impact on the mechanical strength of the chalk matrix.
CO2-Enhanced Oil Recovery Potential of the Appalachian Basin
Authors: Bank G. C. , Riestenberg D. , Koperna G. J. 
Published: December 2007

Abstract
The Appalachian Basin states of New York, Pennsylvania, Ohio, West Virginia and Kentucky have a long, rich history of oil production, with current estimates of cumulative oil production at approximately 3.5 billion barrels of oil. However, estimates of the original oil in-place (OOIP) in the region's mature oil fields suggest that nearly 14 billion barrels were in-place prior to the beginning of production more than a century ago. Although early production data are often "best guesses", the remaining oil in place in this Basin appears to be on the order of 10 billion barrels. Without new efforts, this oil may remain permanently "stranded" following secondary recovery efforts and field closure.
One manner by which a portion of this stranded resource can be recovered is through the use of carbon dioxide enhanced oil recovery (CO2-EOR). The merits of CO2 miscible flooding are well documented and have been demonstrated for more than 30 years in Texas’ Permian Basin, with CO2-EOR efforts currently increasing in the Gulf Coast and the Rocky Mountain Basins. With the current strong oil price situation, the oil producers in the Appalachian Basin may be interested in the CO2-EOR potential in the Basin.
This paper follows a series of reports entitled "Basin-Oriented CO2-EOR Assessment" of the United States1 with an assessment of the Appalachian Basin oil producing states of New York, Pennsylvania, Ohio, West Virginia, and Kentucky. Reservoir simulation using detailed, respresentative data from major oilfields throughout the region indicate that 1,230 million barrels may become technically recoverable if advanced CO2-EOR technology is utilized. The economically recoverable resource will depend on future oil prices and CO2 costs.
Global Seismic Inversion—A New Approach to Integrate Seismic Information in the Stochastic Models
Authors: Guerreiro L. , Caetano H. , Maciel C. , Real A. , Silva F. , Al Shaikh A. , Al Shemsi M. Ali , Soares A. 
Published: December 2007

Abstract
Classical geostatistical inversion methods perform a sequential approach where acoustic impedance (AI) values are generated in a seismic trace by trace basis (Bortolli et al, 1993, Haas A. et al, 1994, Grijalba-Cuenca et al, 2000). These methods need a priori knowledge of areas of poor seismic quality, otherwise false "good" correlations between synthetic and real seismic can be artificially imposed.
A new version of the stochastic seismic inversion algorithm (Soares et al, 2006) was recently applied to a complex Middle East carbonate reservoir to evaluate the robustness and efficiency of the new methodology. This reservoir, located onshore Abu-Dhabi, comprises a strong progradational internal geometry with several clinoforms which amplify the internal complexity of the reservoir and have a strong impact on well production.
This iterative methodology is based on global simulations and co-simulations of AI. The process generates several intermediate models. Those that contribute more to achieve an objective function are used to condition the simulations of the next iterations. There is no local imposing of artificial good fit, as it happens in most trace-by-trace approaches. Spatial dispersion and main patterns of AI are reproduced at the final AI cube. Another important advantage of this technique is that the final images reflect the quality of the seismic data through the uncertainty associated to the final seismic impedance cube.
Despite the scarcity of the log data and the small area of the pilot zone compared with the total volume of the entire seismic cube, the proposed method achieved extremely satisfactory results. Both synthetic seismic data and the seismic acoustic impedance cube captured the main local geologic features of this complex reservoir. Final local correlation coefficients, measuring the match between synthetic and real seismic, can be viewed as a measure of the local uncertainty associated to the areas of good and poor seismic.
Optimal Grid Coarsening: A Fast Proxy for Large Reservoir Optimization
Authors: Mamonov A. V. , Couët B. , Bailey W. J. , Prange M. , Djikpesse H. A. , Druskin V. 
Published: December 2007

Abstract
Reservoir simulation models often require grids sufficiently resolved to capture the complexities of the geological structures present so that pressure and saturation profiles are deemed reasonable enough for decisions to be made with confidence. However, high resolution often implies long simulation run times, which is compounded in optimization problems. Reservoir optimization problems usually involve localized decisions, e.g., production control for a specific time-dependent objective function. With this tighter focus on optimization objectives, the reservoir simulator can often be replaced by an approximate proxy function, e.g., decline curves, neural networks and polynomial response surfaces. This accelerates the run time, allowing the optimizer to make more calls to the simulator, but at the cost of simplified physics and some consequent loss of accuracy.
Recent work in numerical solutions of partial differential equations (PDE) by Druskin and Knizhnerman (2000) introduced a finite-volume optimal grid approach to improve solution accuracy of linear PDEs at targeted points of a computational domain. This approach was applied to the solution of electromagnetic and acoustic forward and inverse problems arising in oil exploration and medical imaging. We extend this work to non-linear PDEs by introducing a reservoir simulator that is used as its own proxy. We distinguish our optimal grid from an optimal upscaling in that it may not preserve local features of the model, but will preserve some aggregate objective value used in production optimization. This narrow focus allows greater coarseness than a properly upscaled grid by replacing the fine-grid model with a coarser grid whose coarsening is determined by an optimizer that preserves the accuracy of a predefined aggregate objective value.
In this work we optimize injection and production rates to maximize the field oil production total (FOPT) over a fixed period of time. The proxy optimizer will seek the best coarsening that preserves this objective value over a range of injection/production rates for each well. The resulting coarse-grid model has a similar physical behavior in these output values to that of the fine-grid model. The grid coarsening problem is a non-linear discrete optimization problem, where the optimizer adjusts the grid coarsening while preserving the fine-grid response of interest. Although we focus on FOPT here, other reservoir objectives can also be handled.