bluuebunny/crossref_metadata_2025_split huggingface dataset:
Use of Satellite Radar Images in Surveillance and Control of Two Giant Oilfields in California
Authors: Patzek Tad W. , Silin Dmitriy B. , Fielding Eric 
Published: December 2007

Abstract
A global analysis of the evolution of an entire giant oilfield is now feasible. The oilfield can be viewed as a single complex system consisting of reservoir rock and fluids, and coupled injectors and producers. The vertically averaged areal signatures of primary and waterflood projects in the field can be tracked in time as the displacement of ground surface above these projects. The Synthetic Aperture Radar interferograms (InSAR) from satellites are the enabling technology. In this paper, we add a new element to our multilevel, integrated surveillance and control system: time-lapse satellite InSAR images of the oilfield surface. In particular, we analyze ten differential InSAR images of the South/North Belridge and Lost Hills diatomite fields, CA, between 04/95 and 12/99. The images have been reprocessed and normalized to obtain the ground surface displacement rate. In return, we have been able to calculate section-bysection the net subsidence of ground surface over the entire field areas. The calculated subsidence volumes are thought to be close to the subsidence at the tops of the reservoirs. The images show that the rate of subsidence has decreased in some parts of Lost Hills and Belridge, while it increased in others. Using the production and injection data from the California Conservation Commission and Chevron, we have been able to demonstrate the remarkable behavior of both fields: (1) There is recirculation of injected water through the "tubes" of damaged soft rock that link injectors with producers, resulting in diminished pressure support from the waterfloods. (2) Consequently, despite more water injection, there is more subsidence in Sections 29, 34, and 33 in Belridge and in Sections 29, 4, 5, and 32 in Lost Hills. (3) As much of the injected water is recirculated, the rate of subsidence is proportional to water production rate. (4) Compaction remains an important mechanism of hydrocarbon production. (5) In addition to accelerated compaction in the densest and most advanced waterfloods, there is a sizable oil production response to water injection. Means of controlling and improving the existing waterfloods are discussed.
Numerical Simulation and Inversion of Pressure Data Acquired With Permanent Sensors
Authors: Alpak Faruk O. , Torres-Verdin Carlos , Sepehrnoori Kamy 
Published: December 2007

Abstract
We have developed a new axisymmetric solution for the numerical simulation of single-phase fluid flow in permeable media. In this new solution, the governing parabolic partial differential equation (PDE) is transformed into a linear operator problem that is subsequently solved with an Extended Krylov Subspace Method (EKSM). The algorithm yields solutions for pressure at a multitude of times with the same efficiency of that of a single-time solution. Extensive comparisons with analytical solutions show that our simulator yields pressure results with accuracies better than 1%, and favorably competes with commercial simulators in CPU execution times and memory efficiency. Examples of numerical simulation are considered for water injection and variable flow-rate problems. In both cases, we have focused our attention to the description of pressure data acquired with permanent sensors deployed in direct hydraulic contact with the producing formation.
The inverse problem considered in this paper consists of mapping time and space variations of pressure and flow rate into a local distribution of permeabilities. We solve this inverse problem by minimizing a cost function written as the sum of the square differences between the measured pressure data and the corresponding pressure data yielded by our Krylov subspace simulator. A nonlinear Gauss-Newton fixed-point iteration search is used to minimize the quadratic cost function. We also test a dual coarse- and fine-grid approach to accelerate the solution of the inverse problem. Examples of inversion are shown with noise-free and noisy data aimed at understanding the role played by the flow-rate function and the location, spacing, and number of permanent sensors into the accuracy and stability of the inverted permeability values.
Growing Injection Well Fractures and Their Impact on Waterflood Performance
Authors: Gadde Phani B. , Sharma Mukul M. 
Published: December 2007

Abstract
Most water injection wells in waterflooded reservoirs have fractures that grow with time. These fractures can have a significant impact on the reservoir performance (oil production rates, o/w ratio and ultimate recovery).
A single well model that predicts the length of injection well fractures by modeling fracture growth due to fracture face plugging and thermal stresses is coupled with a reservoir simulator to simulate injection wells that have fractures that dynamically grow with time. The relative importance of the injected water quality, formation permeability, injection rate and the temperature of injected water on the rate of fracture growth are demonstrated. The single well model accurately accounts for all the physics of fracture growth at the injector while the reservoir simulator accounts for the large-scale reservoir structure.
The presence of high conductivity fractures in the injectors affects the waterflood sweep efficiency. Results indicate that fracture orientation, rate of fracture growth, injection water quality and reservoir heterogeneity play an important role in determining the oil production rates and ultimate recovery. The results of the simulations can be used to set injection well pressures and rates, specify water quality and to select injection well patterns to maximize oil recovery.
Representation of Fault Zone Permeability in Reservoir Flow Models
Authors: Flodin E. A. , Aydin A. , Durlofsky L. J. , Yeten B. 
Published: December 2007

Abstract
Faults can act as fluid flow barriers, conduits, or barrier/conduit systems in reservoirs. Their accurate representation in reservoir flow simulations is essential if realistic predictions are to be attained. In this work we compute the effective flow characteristics of faults using fine-scale field-based data. The faults we focus on are in porous aeolian sandstone and were formed by shearing along pre-existing joint zones. To find the bulk flow characteristics of the fault zones, we develop a computationally efficient upscaling methodology that combines numerical flow modeling and power averaging. By analyzing faults with different slip magnitudes, we are able to produce a relationship between fault permeability and fault slip. Slip magnitude is one of the few fault parameters that can be measured remotely in the subsurface and we show how it can be used to estimate the variation in permeability along a fault. We present three different flow simulation scenarios using variable fault properties derived using our new procedure. For each scenario, we present a second fitunedfl case where we replace our variable fault-zone permeability by a fault with a constant permeability and width. In one case, we find no significant difference in flow response between the variable and constant permeability faults. The other two cases display differences, mostly with regard to breakthrough time and liquid production rates. Because the reservoir flows considered here are relatively simple, we postulate that the differences between the variable and constant permeability fault descriptions will become greater for more complex systems.
Water Infiltration in Fractured Systems: Experiments and Analytical Model
Authors: Rangel-German E. R. , Kovscek A. R. 
Published: December 2007

AbstractCapillary imbibition is an important mechanism during water injection and aquifer influx in fractured porous media. Better understanding of matrix-fracture interaction and imbibition in general is needed to model effectively these processes. Using an X-ray computerized tomography (CT) scanner, and a novel, CT-compatible core holder, we performed a series of experiments to study air and oil expulsion from rock samples by capillary imbibition of water in a three-dimensional geometry. The air-water system is useful in that a relatively large number of experiments can be conducted to delineate physical processes. Different injection rates and fracture apertures were utilized. Two different fracture flow regimes were identified. The "filling-fracture" regime shows a plane source that grows in length due to relatively slow water flow through fractures. In the second, "instantly-filled fracture" regime, the time to fill the fracture is much less than the imbibition time. Here, imbibition performance scales as the square root of time. In the former regime, the mass of water imbibed scales linearly with time.A new analytical model is proposed for filling fractures incorporating implicit matrix/fracture coupling. Good agreement is found between experiments and calculation. This analytic coupling was obtained by means of solving the saturation diffusion equation with the appropriate initial and boundary conditions. The solution provides the location of the wetting phase front in the fracture and the saturation distribution in the matrix. The solution is analogous to that obtained by Marx and Langenheim1 for the areal extent of an equivalent heated zone in thermal recovery methods. Analogous terms among flow and heat transfer in porous media were found and are also presented.
Uncertainty Assessment of Well Placement Optimization
Authors: Güyagüler Baris , Horne Roland N. 
Published: December 2007

AbstractDetermining the best location for new wells is a complex problem that depends on reservoir and fluid properties, well and surface equipment specifications, and economic criteria. Numerical simulation is often the most appropriate tool to evaluate the feasibility of well configurations. However, since the data used to establish numerical models have uncertainty, so do the model forecasts. The uncertainties in the model reflect themselves in uncertainties of the outcomes of well configuration decisions.We never possess the true and deterministic information about the reservoir but we may have geostatistical realizations of the truth constructed from the information available. An approach that can translate the uncertainty in the data to uncertainty in the well placement decision in terms of monetary value was developed in this study. The uncertainties associated with well placement were addressed within the utility theory framework using numerical simulation as the evaluation tool. The methodology was evaluated using the PUNQ-S3 model, which is a standard test case that was based on a real field. Experiments were carried on 23 history-matched realizations and a truth case was also available. The results were verified by comparison to exhaustive simulations. Utility theory not only offered the framework to quantify the influence of uncertainties in the reservoir description in terms of monetary value but also provided the tools to quantify the otherwise arbitrary notion of the risk attitude of the decision maker. A Hybrid Genetic Algorithm (HGA) was used for optimization.In addition a computationally cheaper alternative was also investigated. The well placement problem was formulated as the optimization of a random function. The GA was used as the optimization tool. Each time a well configuration was to be evaluated, a different realization of the reservoir properties was selected randomly from the set of realizations all of which honored the geologic and dynamic data available from the reservoir. Numerical simulation was then carried out with this randomly selected realization to calculate the objective function value. This approach had the potential to incorporate risk attitudes of the decision maker and was observed to be approximate but computationally feasible.
MPP Simulation of Complex Water Encroachment in a Large Carbonate Reservoir in Saudi Arabia
Authors: Pavlas Emmerick Joe 
Published: December 2007

Abstract
Reservoir simulation has entered a new era with the advent of massively parallel processing and its ability to handle millions of cells. In this study a simulation model was constructed from the geologic model without scale up, the resulting model having 1.38 million cells. The majority of effort was spent on reviewing geologic and engineering data. History match changes were made at the well level and interpolated in Kh and Kv arrays using a deterministic mapping routine. Despite the complexity and model size, a successful history match was achieved in 40 runs. The model has been very successful in identifying well locations for bypassed oil recovery.
A Full Field Simulation Model of the Minagish Oolite Reservoir in Kuwait
Authors: AL-Mutairi Saad , AL-Medhadi Fahad , AL-Ajmi Hamad , Meadows David , Oosthuizen Ulrich R 
Published: December 2007

Abstract
The Minagish Oolite is a thick undersaturated carbonate oil reservoir in the Minagish field in West Kuwait (Fig. 1) containing several billion STB. It is a mature but relatively undeveloped reservoir. Since discovery in 1959, it has produced 10% of its OOIP under a combination of natural depletion, gas re-injection and aquifer drive. Initial reservoir pressure had declined by about 450 psi prior to the Gulf war in 1990. The well blowouts following the war caused a significant pressure drop of another 700 psi. Following the blowout, plans were made to redevelop the West Kuwait fields and increase the production rate starting in 2001 and to sustain the plateau for at least 5 years. This strategy called for threefold increase in the production rate of Minagish Oolite reservoir. Since the existing well inventory and the loss of the gas re-injection facility could not sustain the desired plateau rate, additional field development was required.
To achieve the production target, a multidisciplinary team was formed to evaluate options. The recommended plan required the drilling of additional producers and installing a field-wide peripheral waterflood. The reservoir, however, presented a number of significant challenges to waterflooding, such as the presence of a substantial and not well defined tarmat near the oil/water contact, and uncertainties of lateral and vertical heterogeneities. In 1997 a full-field simulation model was developed, but this model didn't capture the water movement properly because of insufficient reservoir data at that time. As new core was obtained, a refined reservoir description was developed. Building on lessons learned from the previous full-field model and sector models, a new full-field model was developed which significantly improved well-by-well history matches. Although containing twice as many grid cells, the new model ran up to four times faster than the previous model by making use of the Analytical Aquifer option within the model, improved relative permeability curves and other model refinements.
This paper traces the history of the field and the systematic evolution of the development plan. The reservoir simulation efforts including modeling strategy, history matching events, prediction runs, future direction and challenges are also addressed.
Semi-Automatic History Matching Using the Pilot Point Method Including Time-Lapse Seismic Data
Authors: Arenas Eliana , Kruijsdijk Cor van , Oldenziel Tanja 
Published: December 2007

Abstract
In this paper, we evaluate the benefit of using time-lapse seismic in reservoir simulation and handle some of the associated challenges. The problem is tackled from a reservoir engineering perspective, focusing specifically on the use of time-lapse seismic in history matching. A semi-automatic history-matching procedure is presented that uses both production and time-lapse seismic data as conditioning data. The actual integration of the production and time-lapse seismic data is handled in the objective or misfit function, which expresses the misfit between modeled and observed reservoir behavior. The pilot point method was chosen to reduce the large history matching parameter space 1–5. The optimum permeability values at the pilot points were determined using the Levenberg-Marquardt optimization algorithm.
The semi-automated method is tested on a 2D synthetic reservoir. The results indicate that for a case with abundant production data, time-lapse seismic sometimes yields only minor improvements in the final history matched model. However, when production data is limited, time-lapse seismic improves the history-matched permeability fields considerably by correctly identifying and locating the major heterogeneities of the permeability field. In addition, the sensitivity studies show that if pilot points are located in or near heterogeneities, the automatic history-matching algorithm has a better chance of correctly locating the heterogeneities. Furthermore, a seismic noise sensitivity analysis shows that seismic noise impedes accurate determination of the history-matched parameters.
The results of this research demonstrate that a history-matching procedure including time-lapse seismic can improve reservoir characterization and modeling. It can be used as a reservoir management tool to optimize in-fill well locations, enhanced oil recovery projects, and economic evaluations. The semi-automated procedure allows engineers to work more efficiently with larger reservoir models and extensive dynamic conditioning data sets.
A Case Study Challenges the Myths of Horizontal Wells in High-Productivity Reservoirs
Authors: Dashti Q. , Ma E. D. , Kabir C. S. 
Published: December 2007

AbstractNumerous case studies substantiate the merit of horizontal drilling, especially in coning situations. Nonetheless, the burning question remains: do horizontal wells assure performance optimization in all cases? This paper explores the effectiveness of horizontal wells in a high-permeability (kh &gt; 3,000 md), high-anisotropy (kv/kh &lt; 0.01) Burgan Third Middle Sand (3MS) reservoir in Kuwait. To do so we built a sector model containing 35 wells to match 50-year history in a strong edge-water-drive system. With the history-matched model, we examined performance of horizontal wells under various scenarios. These scenarios included reservoir and completion considerations, such tubing size, well length, and high-slant configuration. For comparison, we measured the performance of a horizontal well against its vertical counterpart in terms of water-breakthrough time, oil acceleration, and incremental recovery.Results show that horizontal wells do not appear to offer any decisive advantage over their vertical counterparts in terms of breakthrough time and ultimate recovery. That is because unique reservoir characteristics, such as high-anisotropy (kv/kh) and low-length-to-thickness (L/h) ratios, coupled with high productivity index (PI), all contributed adversely to horizontal wells' performance when compared with vertical wells. Horizontal wells' PI may be higher but the vertical well is equal to the task of delivering desired oil rates, although with a somewhat larger drawdown. In essence, the primary constraint on well performance is the tubing size, not PI. Therefore, a well with large tubing will achieve optimal performance, regardless of its orientation in the 3MS reservoir.
Propellant-Assisted Perforating in High-Pressure and Temperature Wells at Campo Bosque in Northern Monagas State
Authors: Ramirez Javier , Barrera Jose , Romero Roberto , Figueroa Frank , Almanza Edgar , Folse Kent 
Published: December 2007

Abstract
The Pirital Field is located in the eastern basin of Venezuela and is characterized by large high-pressure/high-temperature (HP/HT) reservoirs. The geology is complex with heavy faulting, natural fracturing and high-formation dip angles. To optimize the evaluation of the new HP/HT reservoirs in the Bosque block, a development and delineation project team was assembled. To fully assess the potential of the HP/HT reservoirs, two exploratory wells were drilled (PIC-25 and PIC-26) to confirm the feasibility of drilling and completing these wells. The mission of the project team was to deliver prolific producers with optimum completion efficiency while minimizing environmental impact.
One of the most important tasks was the perforation planning to ensure adequate connectivity to the reservoir in order to successfully test and evaluate each respective horizon. Available petrophysical data indicated that the reservoirs under study were of low porosity (&lt;5%) and permeability (&lt;0.8 md) at a measured depth of 21,000 ft. Several perforating strategies were evaluated, and the final decision was to use propellant-assisted perforating in scenarios where conventional hydraulic fracturing was not in the evaluation plans.
This paper covers the methodology used to validate the application of propellant-assisted perforating in HP/HT wells. The perforation-gun assembly selection, along with the analysis of generated peak pressures from the propellant burn process, will be reviewed. The mechanical configuration, wire line design and benefits derived from propellants will be fully explained.
The results presented in the two case histories presented will show the benefits observed in the form of low completion skin factors. Propellant-assisted perforating has shown to be an effective method for achieving perforation breakdown when testing tight, HP/HT sandstone reservoirs.
Analysis and Prediction of Microseismicity Induced by Hydraulic Fracturing
Authors: Warpinski N. R. , Wolhart S. L. , Wright C. A. 
Published: December 2007

Abstract
This paper presents an analysis of the stress and pressure changes caused by hydraulic fractures and evaluates the likelihood and causes of microseismic activity in the vicinity of the fracture. Coupled with the formation stresses, pressure, and properties, the analysis predicts where microseisms should occur in relation to the fracture and makes possible accurate interpretation of the significance of the microseismic events. The most important factor controlling the seismically active zone is the coupling of the fracturing pressure into the formation. Thus, liquid saturated reservoirs experience much more widespread activity than gas reservoirs. The analysis also shows that the fracture tip induces large shear stresses that result in a local zone of instability. Such a zone is the primary reason that microseisms accurately map out the length and height of the fracture since considerable microseismic activity occurs around the tip as it propagates
Fluid Characterization for Placing an Effective Frac/Pack
Authors: Morales R. H. , Gadiyar B. R. , Bowman M. D. , Wallace C. , Norman W. D. 
Published: December 2007

Abstract
While fluid characteristics are vital for effective proppant placement during any fracturing treatment, they become even more critical for frac/packing high permeability formations. Fluid properties are also important for proper clean up and flowback after pumping. Properly designed fluids can minimize production skin. This paper addresses the selection of conventional guar fluids for frac/packing applications.
The discussion focuses on the shear versus viscosity behavior within the fracture before and after the onset of tip screen out. It also deals with the near-wellbore and fracture cool down caused by the injection of the cooler fluids that are pumped ahead of the frac/pack treatment. Shear rate and temperature are used to select the appropriate fluid. The paper presents criteria for estimation of breaker loading to assure post-treatment clean up.