bluuebunny/crossref_metadata_2025_split huggingface dataset:
Quantitative Use of 4D Seismic Data for Reservoir Description
Authors: Dong Yannong , Oliver Dean S. 
Published: December 2007

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

AbstractConditioning 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

Abstract
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

Abstract
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

Abstract
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

AbstractCrude 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

Abstract
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&#39;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.