bluuebunny/crossref_metadata_2025_split huggingface dataset:
Quantifying Rock Capillary Strength Behavior in Unconsolidated Sandstones
Authors: Han G. , Dusseault M. B. , Cook J. 
Published: December 2007

Abstract
Changes in water saturation or rock wettability can lead to rock instability and sand production. The effects of saturation on rock strength have two origins - chemical sensitivity and changes in capillary forces. In this paper, a detailed study of capillary rock strength behavior after water breakthrough is carried out for four different models. These four models account for particle-particle interactions and include spherical particles in tangential contact, differently sized spheres in tangential contact, squeezed contacts, and detached spheres. The effects of fluid properties (e.g. contact angle and surface tension), rock properties (e.g. particle size, size ratio, contact fabric), and deformation of loaded rock on capillary strength have been mathematically expressed and quantified.
The model calculations indicate: For all the models, capillary strength increases linearly with increasing surface tension between fluid phases.Contact angle influences both the magnitude of capillary strength and its variation with saturation. The larger the contact angle, the lower the magnitude (under the same water saturation) and the faster its decrease with increasing saturation.If the particle size is uniform, small particle size results in high capillary strength. If particles have different sizes, the size ratio of the particles has a similar influence on capillary strength as does fluid contact angle: it affects both the magnitude of capillary strength and its variation with water saturation. However, the relationships are different: the smaller the size difference, the higher the magnitude and the slower its decrease with saturation.For the detached and squeezed models the capillary force (or strength) firstly increases with water saturation, then decreases after a critical saturation, in contrast to the tangential contact model where capillary force always decreases with water saturation.Through the introduction of the strain concept into the capillary models, they can be used to describe capillary strength variations with rock deformation. It is found that capillary strength more-or-less reaches a maximum when spheres are tangentially contacted, and decreases in both the squeezed and detached states, but decreasing much faster with increasing deformation in the squeezed state.
These improvements in the micromechanical modeling of sands will be used to build our understanding of sand production in very weak or unconsolidated rocks, clarifying how sand production is affected by changes in saturation.
Subsidence Prediction and Inversion of Subsidence Data
Authors: Fokker Peter A. 
Published: December 2007

Abstract
This paper presents a forward model for subsidence prediction and an inversion model to calculate the reservoir behaviour from subsidence data. The forward model employs combinations of analytic solutions to the elasticity equations, which approximate the boundary conditions. There are only few free parameters and consequently the calculation times are limited. Still, the model is applicable to a multi-layer subsurface with elasticity parameters changing per layer. The inverse problem is usually ill-conditioned or ill-posed and has therefore been regularized by introducing a priori data about the pressure field or by imposing a certain amount of smoothness. The strength of the regularization parameters are best determined using the model resolution of the inversion and synthetic cases. These also can be used to optimize the experimental design. Inversion of a synthetic case with a "wrong" forward model shows the importance of obtaining reliable subsurface elasticity data. Without such data, the quality of the inversion can be highly compromised.
The Impact of Mud Infiltration on Wellbore Stability in Fractured Rock Masses
Authors: Chen X. , Tan C. P. , Detournay C. 
Published: December 2007

Abstract
Wellbore stability analysis has been included at the well planning stage of many operating companies for its beneficial effect on improvement of drilling efficiency and cost. Such analysis can be very complex and time-consuming due to numerous factors contributing to borehole instability. As such, many wellbore stability analyses take only a few of the factors into account and are mainly based on continuum mechanics. In addition to the detrimental effect of bedding planes and fractures on borehole stability, the rock masses will become more prone to wellbore instability along fractures penetrated by mud due to reduction in the fracture friction angle. However, very few wellbore stability analyses consider the impact of friction angle reduction of fractures when they are infiltrated with mud. Analyses without considering these factors may yield significant errors and misleading predictions.
In this paper, coupled numerical analyses, using UDEC, are presented to investigate the impact of mud infiltration into fractures on wellbore stability under both isotropic and anisotropic stress states. A symmetric regular fracture geometry is considered in the analyses. A simplified, but reasonably realistic, approach is developed to take into account the friction angle reduction of the fractures that occurs when infiltrated with mud. This approach evaluates the extent of mud infiltration and reduces the friction angle of fractures located in the mud-infiltrated region accordingly. The domain of mud infiltration can be either circular or elliptical around the wellbore, which covers both isotropic and general stress conditions.
The Geomechanical Prediction of Fracturing in the Circle Ridge Field, Wind River Basin, WY.
Authors: La Pointe Paul R. , Hermanson Jan 
Published: December 2007

Abstract
Improved recovery of oil from fractured reservoirs often requires understanding how the intensity and orientation of natural fractures vary throughout the reservoir or field. Image logs or core provide excellent fracture data on these fracture parameters in the vicinity of a well, but these often still leave a large portion of the reservoir unknown. Modern 3D land-based seismic can be used to help constrain fracture intensity and directionality in the critical regions between wells, but acquisition and processing may be technically difficult or uneconomic, particularly in older onshore fields where optimized tertiary recovery schemes could increase recovery.
Many important fractured oil reservoirs form in a compressional setting in which there have been various episodes of folding and faulting. The faulting can be quite complex, and involve reverse or thrust faulting, as well as extensional (normal) faulting. Because these folding and faulting events probably represent the peak strain events that the reservoir has experienced, it is likely that the reservoir-scale fracturing developed in response to one or more of these events. Thus, if the strain history could be technically and economically mapped and compared to fracture data from image logs or core, it would be possible to constrain the orientations and intensity of fracturing throughout the reservoir.
This process was carried out at the Circle Ridge Field, in which the fracturing in the Tensleep and Phosphoria Formations controls the efficiency of recovery processes. A 3D palinspastic reconstruction of the strain history for the folding and faulting of this Field was carried out. The strain pattern developed after each stage of deformation was compared to image log and surface fracture data. It was found that the strain produced by the initial folding event predicts fracture orientations and intensity variations quite accurately throughout various structural blocks, and that later faulting events do not seem to have influenced the fracture pattern except in the immediate vicinity of the large faults. This geomechanically-based model of fracturing is being used as the basis for designing tertiary recovery processes for the Field.
Improving Permanent Downhole Gauge (PDG) Data Processing via Wavelet Analysis
Authors: Ouyang Liang-Biao , Kikani Jitendra 
Published: December 2007

Abstract
One of the major issues in processing permanent downhole gauge (PDG) data is that there exist too many transients over a reasonable time period, say six months. A formula has been proposed to predict the transients that may be detected or missed. Reasonable prediction has been achieved via the formula.
Noise usually exists in data recorded by permanent downhole gauges. Denoising is thus one of the most important steps in PDG data processing. In order to denoise the data, data noise level must be estimated beforehand. Unfortunately, the data noise level is typically case-dependent, therefore, it is impossible to identify a universal value for the level that may be used for all the application scenarios.
One appropriate approach to estimate the noise level is to first best fit the data, subtract predicted pressure response from recorded values, and then calculate the noise level based on the difference1. We proposed to apply nonlinear regression via Polytope method2 for best-fitting PDG data to determine the noise level. It is found that the new approach is superior to the least square error (LSE) linear regression as used by Khong1, because the bottomhole wellbore pressure response in a well should be treated as a nonlinear function of time over majority of the well production/injection/shut-in period. Unless very small range of the data (say 2 hours) is considered, linear pressure response with time is not anticipated. Furthermore, with nonlinear regression through the Polytope approach, there is no strong restriction in data quantity and data density, hence, automatic detection of data noise level can be implemented.
Other improvements to the PDG data processing procedure, such as trend analysis, steamlinization of data preprocessing, step outlier removal, and so on, will also be discussed.
Characterization of Reservoir Fluid Dynamics from Multiple Downhole Permanent Sensors
Authors: Manin Y. , Charara M. , Delhomme J. P. 
Published: December 2007

Abstract
In this paper, we first provide guidelines for selecting the most appropriate permanent downhole sensor or combination of sensors for reservoir monitoring, given fluid and rock characteristics. This selection is applied to pressure, electrical, and seismic sensors, based on their respective response equations to formation and rock properties.
We then present two synthetic cases illustrating the interpretation of permanent monitoring data, with emphasis on the benefits of data fusion and data assimilation, referring respectively to the use of multisensor and time-lapse data; more specifically, we show how those approaches enhance the convergence of the inversion process towards the solution.
Using Multilateral Well Technology to Improve Recovery Factor by Water Flooding in a Giant Mature Oil Field in Venezuela Lagunilla Inferior (LL-03)
Authors: Gutiérrez O. , Alter D. , Romero M. , Carreno Z. , León A. , Mohtadi M. 
Published: December 2007

Abstract
The Lagunilla Inferior is located on the eastern part of Lake Maracaibo. It covers an area of around 300 km², with an original oil in place of 6,900 MMSTB and with a total of 1051 wells. The overall recovery factor is around 20% and the current oil field production rate is 30,000 STB/day.
To improve the recovery factor during the 70 years of field production life, four water injection projects in different areas of the reservoir have been implemented. In a recent effort to improve the recovery factor in a selected part of the reservoir with higher residual oil saturation but very low reservoir pressures (300-450 psia), an integrated reservoir study was conducted. In this study the water injection with vertical wells were compared with multilateral well technology by using a numerical simulation model. The water flooding scheme with multilateral wells as injectors and producers shows in this study the highest recovery factor, the best economics indicators and the lowest operational activities compared to the vertical well concepts.
In this paper the results of different pattern concepts and the detailed project planing will be presented. The first phase of the project (drilling of two injection wells and one producing well) will be implemented this year.
Long Distance Decision Making and High Risk Drilling
Authors: Ramp Erich R. 
Published: December 2007

Abstract
Today the Petroleum Industry is moving into more high-risk projects than ever before. A key to the successful completion of many of the projects is the mitigation of project risks and uncertainties. One aspect of risk mitigation is the making of timely and geo-technically correct decisions during drilling operations. The geologically complex nature of many of today’s mega projects often requires numerous experts to be involved in the decision process. If the specific professionals are not available at critical junctures, the results are increased project risk, increased costs, or probably both. A solution is to bring the risk to the experts as/when needed versus taking the experts to the risk.
The Hamaca Project, located in the Eastern-Central portion of Venezuela, is an excellent case example of the benefits of long distance decision making. In Hamaca bringing the drill bit to the experts is the norm not the exception. In just over one year of horizontal drilling operations Petrolera Ameriven drilled approximately 110 horizontal well bores with nearly 564,000 feet of lateral lined section. The lined drain holes had a cumulative 90% net sand contact rate. These results far exceeded original expectations and were in large part due to the long distant decision making.
Upgrading a Heavy Oil Using Variable Frequency Microwave Energy
Authors: Jackson Cindy 
Published: December 2007

Abstract
Heavy oil upgrading experiments were conducted using a variable frequency microwave. While microwave energy itself is readily available as a laboratory technique, microwave ovens that produce frequencies other than 2450 MHz are not. We were able to determine the effect of frequency, by using a variable fre- quency unit at a facility in North Carolina.
Results were promising despite the rapid screening which was employed. Experimental variables included additives, reaction time, and frequency. The addition of activated carbon produced an oil that met pipeline specifications for viscosity and density.
Coke formation determined only on the molybdic acid–iron powder combination; was less than 2 wt.%. This encouraging coke finding may indicate a low coking propensity due to selective heating whereby the bulk of the sample remains at cooler temperatures and reactions are carried out very rapidly.
Overall, the experimental results emphasized that different combinations of material interacted differently at different frequencies. This finding is of utmost importance because the screening of additives has traditionally been focused on 2450 MHz and 915 MHz, which — depending upon the reactants — may not be appropriate for optimum interaction. Frequency was found to have a marked effect upon upgrading.
Waterflooding by Horizontal Injectors and Producers
Authors: Popa Constantin G. , Turta Alex T. 
Published: December 2007

Abstract
Using horizontal wells in a waterflooding process, a higher sweep efficiency for less cost is expected as opposed to the use of classical patterns by vertical wells. However, the use of horizontal wells is very sensitive to the well pattern designed to operate such a process. The paper presents an analysis of how the overall efficiency of a waterflooding process is influenced by the well pattern using horizontal injectors and producers in different configurations.
Recent investigations used vertical injectors and horizontal producers, with the horizontal well completed at the top of formation and having its toe close to the injection well, which was perforated at the lower part of formation. This process, known as a short-distance Toe-To-Heel Waterflooding "(TTHW) process", was found sound for the light-heavy oils with viscosity up to 2,000 cP, and proved to have maximum efficiency for relatively thick formations.
The general necessity to inject higher water rates, simultaneously with the preservation of a certain control on the injection, prompted the investigation of the use of horizontal wells as injectors both for light-heavy oil and light oil recovery in thin oil reservoirs in a long distance displacement configuration, as well.
A two phase two dimensional numerical simulator for thin formations to investigate the Waterflooding by Horizontal Injectors and Producers, including an "areal" TTHW process, was used. Both the sink/source and the discretized well were considered, in order to estimate the effect of pressure drop along both injectors and producers on the oil recovery performance. The results showed that the pressure loss along the horizontal section has a significant influence on the sweep efficiency.
A numerical simulation study for 10 oils having viscosities between 1 cP and 150 cP was undertaken. The study was performed for both long-distance and short-distance displacement configurations, although for some oil viscosity values it was made just for illustrative purposes. The main parameters, such as time of water break-through, oil recovery at break-through, sweep efficiency, injection-production pressure drop, etc were analyzed in all cases.
For optimization purposes two types of configuration were investigated: a staggered parallel horizontal wells configuration, having their heels in opposite directions and their toes arranged in a direct line, and an L shaped configuration, with perpendicular horizontal wells having their toes relatively close to each other.
Challenges Faced in Well Construction as Heavy Oil Exploitation Goes Deeper
Authors: Davy Claire 
Published: December 2007

Abstract
This paper introduces the Mukhaizna Heavy Oil Project, one of PDO’s (Petroleum Development Oman) "T50" projects that expects to increase recovery of these Middle East reserves to a 50% Target.
Well construction faces several extra challenges for this, the world’s deepest reservoir yet to be thermally exploited. Loss zones and cementation hurdles require innovative solutions, even for vertical wells.
The methods by which the field is to be exploited by predominantly vertical wells are outlined. The limitations faced in designing these wells are set out. The corresponding subjects of further technology development are catalogued.
Delivery of this paper encourages an environment for reception of feedback from both experts and suppliers to assist in planning a path to obtaining solutions and putting these into practice.
Optimization of Smart Well Control
Authors: Yeten Burak , Durlofsky Louis J. , Aziz Khalid 
Published: December 2007

Abstract
Downhole inflow control devices allow for the flexible operation of nonconventional wells. They provide the ability to independently control each branch of a multilateral well and can therefore be used to maximize oil production or to minimize the production of unwanted water or gas. In this paper, a method for the optimization of the operation of smart wells; i.e., wells containing downhole sensors and inflow control devices, is presented and applied. The method entails the use of a conjugate gradient optimization technique applied in conjunction with a commercial reservoir simulator that contains a detailed multisegment well model. The overall optimization technique is applied to several example problems involving different types of wells and geological models as well as multiple geostatistical realizations. The improvement in predicted performance using inflow control devices, which is as high as 65% in one case, is demonstrated for all of the examples considered. There is, however, significant variation in the level of improvement attainable using these devices, so sophisticated decision-making techniques may be required when considering their use in practice.
New Method For Predicting Deliverability From Variable-Rate Drawdown Data
Authors: Pascal H. , Quillian R.G. 
Published: December 2007

Abstract
In this investigation, a new method was developed for analysis of variable-rate drawdown tests of low-permeability gas reservoirs. Rate variation, usually declining during the test, is considered as a continuous function of time, contrasted with most other multiple-rate solutions which superpose the effects of representative rates corresponding to discrete time steps.
A computer program was developed to perform a non-linear least squares determination of the coefficients in the equation which uniquely describes the rate-time profile recorded during the test. A mathematical model was formulated in terms of the Volterra linear integral equation. The unique pressure response as a function of time, corresponding to what the authors' term a constant rate, may be determined from this model. A companion computer program was written to provide a numerical solution of the model, including values for effective gas permeability and skin. After obtaining from the model appropriate pressure response f(tk) as a function of time, conventional (semilog) analytical procedures may be used.
Several field cases are presented which illustrate the good match achieved between predicted pressure history and that recorded at wells pressure history and that recorded at wells producing from a low-permeability gas reservoir. producing from a low-permeability gas reservoir. In the case of an unfractured reservoir, a good history match was achieved without further assessment of permeability and skin data. Wells subjected to hydraulic stimulation exhibited the enfluence of the vertical fracture system during the drawdown test resulting in optimistic values for permeability and skin. In such cases, a good history match was achieved by correcting permeability using the methods proposed by Russell and Truitt.

Introduction
Methods for analyzing flowing well behavior to obtain estimates of the physical parameters of the reservoir require as a fundamental condition that flow rate be held constant. This is an unreasonable requirement applied to low-permeability gas reservoirs where rates often vary (decline) uncontrollably during a single-point drawdown test. Several descriptions appear in the literature for conducting and analyzing variable-rate tests, usually entailing application of the principle of superposition in time.
P. 207
Relative Permeabilities And Capillary Pressure In The Burgan And Wara Sands
Authors: Hetherington George 
Published: December 2007

1961 Middle East Regional Meeting; Dhahran, March 27–29, 1961
Gas-oil relative permeabilities of the Burgan and Wara sands can be roughly correlated with absolute permeability. Gas relative permeabilities are related to oil relative permeabilities and to capillary pressure by the Kozeny-Carman equation only if the tortuosity coefficient is considered a function of saturation and different for each absolute permeability. It must be determined empirically.
A regular relation was observed between initial water saturation and the amount of oil which can be displaced by water. This seems to be the same for Uncleaned cores taken with oil-based mud and for extracted cores. It therefore seems reasonable to assume that it also applies to the sand in situ in the reservoir. If it does, the oil recoverable by water drive can be estimated from the initial interstitial water saturation.
Initial water saturation of the Burgan and Wara sands decreases as absolute permeability increases. The residual oil saturation after water flooding also decreases with increasing absolute permeability. From this and other evidence, it appears that these sands are partially oil and partially water-wet. At low water saturations they exhibit the behaviour of water-wet sands but at higher water saturations they behave as though they were oil wet.