bluuebunny/crossref_metadata_2025_split huggingface dataset:
Improved Reservoir Modeling With Time-Lapse Seismic in a Gulf of Mexico Gas Condensate Reservoir
Authors: Waggoner J. R. , Cominelli A. , Seymour R. H. 
Published: December 2007

Abstract
Time-lapse 3D, or 4D, seismic has been tried in several fields to date, with some good case studies published to demonstrate the utility of the 4D seismic information. While another 4D case study would be useful, this paper describes 2 novel aspects of a recent application in the Gulf of Mexico. First, the target reservoir contains a gas condensate fluid under primary depletion, so pressure, rather than saturation, changes create the observed 4D acoustic response. Further, the primary impact of the pressure change is to the fluid composition as the initially dense gas phase lightens as condensate drops out below the dew point. The result was a 3.6% change in acoustic impedance predicted in the feasibility study.
Second, the 4D seismic result was used to constrain an optimized history matching procedure along with the production data. After describing the seismic history matching method used, the paper will discuss the changes to the reservoir model that resulted. For comparison, some results using a production data only history matching procedure are also presented. While the neither set of history matching results should be considered unique, they do give some insight into the structure of the reservoir that should be considered for optimal reservoir management, and provide an indication of the impact of 4D information in history matching.
Improved Filtercake Cleanup Practices for Horizontal Well Completions in Unconsolidated Sands: Correlation Models for Filter-Cake Removal
Authors: Burnett David , Gutierres Fernando , Serrano Gerardo 
Published: December 2007

Abstract
Improved well productivity from high performance horizontal wells depends upon efficient drilling and completion practices in the formation sand. This study presents empirical models for estimating the breakthrough time and regained permeability for selected nondamaging drill-in fluids (DIFs). The models provide a clear indication of formation damage and proper cleanup treatments for a range of reservoir conditions analyzed in this study. We determined values of breakthrough time and regained permeability for common polymer-carbonate and sized-salt/saturated brine DIFs for a range of reservoir properties including temperature, drill solids content, and percent of acid in the cleanup treatment. These DIFs form tight, thin filtercakes that control fluid leakoff and afford more complete wellbore cleanup properties than standard drilling muds. But determining the appropriate cleanup technique is often difficult.
Work began by creating a large database of 101 tests with 8 independent variables including (1) type of drill-in fluid, (2) temperature, (3) screen type, (4) presence of gravel pack, (5) formation type, (6) type of drill solids, (7) concentration of drill solids, and (8) cleanup treatments.
In measuring the regained permeability, we used a linear-flow cell apparatus. In measuring the breakthrough time that particular cleaning procedures take to flow across the filter cake, we used a ceramic disc cell apparatus.
We analyzed the importance of each variable. After that, we identified the independent variables we were taking into account during this research. Those variables were (1) temperature, (2) drill solids content, and (3) cleanup (concentration of hydrochloric acid in the cleanup treatment). Then we generated a matrix for each set of experiments that allowed us to organize and measure the conditions we were looking for, regained permeability and breakthrough time.
We used statistical software to select properties, formation, and diagnostics of the models and to develop relationships among the properties of the DIF's. We developed four new empirical models for estimating the breakthrough time and regained permeability in polymer carbonate and sized salt. High correlations resulted with R2 values between 0.851 and 0.986 corroborated by close values of adjusted R-square and low P-values give validity to the correlations found. This technique gives a broad overview of the formation damage as well as the proper cleanup treatment for similar conditions presented in the field.
Well audits of horizontal wells drilled and completed using advanced technology. Cleanup methods have closely matched predicted values of well PI.
Reservoir Characterization During Underbalanced Drilling: Methodology, Accuracy, and Necessary Data
Authors: Vefring Erlend H. , Nygaard Gerhard , Fjelde Kjell Kåre , Lorentzen Rolf Johan , Nævdal Geir , Merlo Antonino 
Published: December 2007

Abstract
In this paper a novel methodology for reservoir characterization during underbalanced drilling is presented. In this methodology we are using a transient wellflow model coupled to a transient reservoir model, and use estimation techniques to estimate reservoir properties. Our focus is to estimate the permeability and reservoir pressure along the well, using measured data usually available while drilling. The measured data are outlet rates, pump pressure and downhole pressure. The liquid injection and gas injection rates are used as input to the model.
Our finding is that estimating permeability and reservoir pressure simultaneously is a difficult estimation problem, and may lead to large uncertainties in the estimates. If we assume that the reservoir pressure is known, however, reliable estimates of the permeability is obtained. A methodology for uncertainty analysis is also presented and can be used to evaluate necessary measurements for proper reservoir characterization.
Effects of Formation Damage and High-Velocity Flow on the Productivity of Perforated Horizontal Wells
Authors: Tang Yula , Yildiz Turhan , Ozkan Erdal , Kelkar Mohan 
Published: December 2007

Abstract
A comprehensive semi-analytical model is built to investigate the effects of drilling/perforating damage and high-velocity flow on the performance of perforated horizontal wells. In our previous papers1,2, we presented a semi-analytical model for completed horizontal wells by coupling the 3D reservoir flow model and the wellbore-hydraulics model and discussed the pseudo-skin approach for clean perforated completion. In this paper, the additional pressure drop due to formation damage and high-velocity flow are addressed and incorporated into the previous semi-analytical model. The reservoir model considers the 3D convergent flow into individual perforations, flow through the damaged zone around the wellbore and the crushed zone around the perforation tunnels as well as the additional pressure drop due to non-Darcy flow in near wellbore region. Both oil and gas wells are discussed.
The expressions for additional pressure losses due to perforating damage, drilling damage and high-velocity flow can be used to optimize perforating parameters and to decompose the total skin into its components (perforation pseudoskin, damage skin, and non-Darcy skin).
Productivity Changes in Reservoirs with Stress-Dependent Permeability
Authors: Raghavan R. , Chin L. Y. 
Published: December 2007

Abstract
The goal of this paper is to present correlations to permit engineers to evaluate productivity losses in reservoirs with stress-dependent permeability (stress-sensitive reservoirs). The correlations developed in this study are intended to be used in determining production forecasts. For stress-sensitive reservoirs, the reduction in permeability caused by change in the stress state during production, if any, may significantly reduce expected productivity. It is the purpose of this paper to address methods to ascertain changes in productivity as a result of stress-dependent permeability. A rigorous mathematical model that couples geo-mechanical and fluid-flow aspects is used to correlate productivity reductions with time. The reduction in productivity index (PI) is expressed as a function of operating variables such as overburden stress, mechanical properties, wellbore pressure, drainage area etc. The expressions developed in this study may be directly incorporated (after tuning) in simulators to properly account for changes in productivity.
Three-Phase Displacement Theory: An Improved Description of Relative Permeabilities
Authors: Juanes Ruben , Patzek Tad W. 
Published: December 2007

AbstractA quantitative understanding of three-phase flow in porous media is required to address many diverse processes in the subsurface, e.g., improved oil recovery, CO2 sequestration, and aquifer clean-up. In turn, all predictive models of three-phase flow originate from interpretations of onedimensional laboratory experiments; when these interpretations are flawed, so are the models. In this paper we revisit the foundations of displacement theory in three-phase flow and provide the most general conditions for any relative permeability model to be physical anywhere in the saturation triangle. In doing so, we put to rest a controversy that has persisted in petroleum literature for the better part of the last six decades.When capillarity is ignored, the system of conservation laws describing incompressible immiscible flow should be strictly hyperbolic. This natural property of the system fails for most relative permeability models used today. We identify necessary conditions that relative permeabilities must obey to preserve strict hyperbolicity. These conditions are in agreement with experimental observations and pore-scale physics.We also present the most general analytical solution to the Riemann problem (constant initial and injected states) for three-phase flow, and describe the characteristic waves that may arise, concluding that only 9 combinations of rarefactions, shocks and rarefaction-shocks are possible. Some of these wave combinations have been overlooked by many because of the associated conceptual and mathematical difficulties.The analytical developments presented here will be useful in the planning and interpretation of three-phase displacement experiments, in the formulation of consistent relative permeability models, and in the implementation of streamtube simulators.
Prediction of wettability variation and its impact on waterflooding using pore-to reservoir-scale simulation
Authors: Jackson Matthew D. , Valvatne Per H. , Blunt Martin J. 
Published: December 2007

Abstract
We describe a pore-to reservoir-scale investigation of wettability variation and its impact on waterflooding. Our aim is to demonstrate that network models incorporating realistic pore-space geometry and physics may be used as a tool to predict wettability variations and their impact on flow.
We successfully predict experimental data for water-wet and mixed-wet media using a three-dimensional pore-scale model of a Berea sandstone. We then focus upon the effect of variations in initial water saturation associated with capillary rise above the oil-water contact (OWC). This may lead to wettability variations with height, because the number of pore-walls which may be rendered oil-wet during primary drainage increases as the oil saturation increases.
We investigate the validity of empirical hysteresis models in which scanning curves are used to connect bounding waterflood and drainage curves for a given initial water saturation. If the wettability varies with initial water saturation, we demonstrate that the bounding waterflood curve, which is measured from the lowest water saturation (and hence the most oil-wet conditions), does not yield the correct scanning curves at higher water saturations.
We use network model derived relative permeabilities in a conventional field-scale simulation of waterflooding a typical North-Sea reservoir. If the wettability varies with height above the OWC, we demonstrate that the displacement efficiency is high. This is because the water relative permeability curves are generally low (characteristic of water-wet media), yet the residual oil saturation is also generally low (characteristic of oil-wet media). Assuming that the reservoir is uniformly water-wet or oil-wet, or using empirical hysteresis models, leads to an underestimate of recovery.
Using a physically-based pore-scale approach predicts behavior at both the core and field scales that is qualitatively different from that predicted by conventional relative permeability models. This work suggests that where there is a wettability trend in a reservoir, the relative permeabilities can have a first order impact on recovery predictions.
Drill Cuttings Injection: A Review of Major Operations and Technical Issues
Authors: Keck Richard G. 
Published: December 2007

Abstract
Since its first use about 15 years ago, drill cuttings injection has grown to become a routine operation performed around the world. This rapid development is due to increasingly stringent environmental regulations and improved costs compared to alternative disposal options. The regulations for overboard discharge of cuttings started with limitations on oil-based muds and has now expanded to include synthetic muds as well. The economics of injection operations have improved as the industry has gained experience with the technology, with added benefits from the economies of scale offered by large capacity injection facilities.
The two critical engineering questions that must be answered for injection applications are: (1) where does the waste go and (2) how much can we safely inject into a well? These questions require integration of a variety of environmental, technical and economic factors that are important for each particular injection operation. The geometry of hydraulic fractures created during solids injection is one of the key issues in most operations. This coupling between solids injection and fracturing is the focus of this paper.
Extending Foam Technology from Improved Oil Recovery to Environmental Remediation
Authors: Mamun C. K. , Rong J. G. , Kam S. I. , Liljestrand H. M. , Rossen W. R. 
Published: December 2007

Abstract
In the petroleum industry, foams are used for improved oil recovery, reducing gas breakthrough to productions wells, and diverting acid in well-stimulation treatments. A substantial body of research on foam for these applications is extended here to the high-permeabilities and low pressures of environmental remediation, through both laboratory experiments and computer simulations based on the laboratory results.
New data confirm that the two steady-state flow regimes identified by Alvarez et al. for petroleum applications exist under conditions relevant to groundwater remediation. The low-quality regime is strongly shear-thinning, in agreement with Alvarez et al. The high-quality regime is more sensitive to surfactant concentration than the low-quality regime, while the low-quality regime is more sensitive to permeability. Therefore, diversion between layers differing in permeability would be more effective in the high-permeability regime, while the low-quality regime has advantages for injectivity and liquid diversion.
A foam simulator can be fitted to these steady-state foam data. Simulations indicate that foam can propagate without gravity segregation over long distances at an overall average pressure gradient of well under 1 psi/ft. Moreover, a simple correlation for gravity segregation developed for petroleum applications works well for aquifers overlain by a vadose zone, as long as the assumptions of that correlation (Newtonian rheology, incompressible flow) are satisfied.
Local steady state would not be achieved in the field if pressure gradient were insufficient for foam generation, however. New results indicate that at moderate ∇p foam may exist in an unstable regime between strong and coarse foam.
High Resolution Downhole Measurements of Porosity and Fluid Saturation While Core Drilling
Authors: Bonnecaze Roger T. , Sharma Mukul M. , Butler Jason E. , Arboleda Gustavo 
Published: December 2007

Abstract
A new method is presented for making high resolution, downhole measurements of porosity and fluid saturations while coring drilling. The method relies on a bank of sensors located in the inner core barrel directly above the drill bit. The sensors allow measurements to be made as the core enters the core barrel and passes by the sensor array. The well-defined cylindrical geometry allows us to construct a cross sectional image of the core at high-resolution (cm scale). The core can then be retrieved to the surface or disaggregated and circulated out as cuttings.
Experimental results are reported for an array of 32 equally spaced electrodes around a cylinder. The electrodes were fired in the opposite protocol, where current is injected across opposite electrodes and measurements of potential differences were made between all other adjacent pairs. The data were then numerically inverted to obtain electrical impedence images (tomograms) of several cross-sections of the core. Results are presented for an oil-saturated 4-inch diameter core from Prudhoe Bay, Alaska. To test the validity of the electrical tomograms, the core was also X-ray CT scanned at high resolution to obtain accurate maps of porosity and oil saturations. A comparison of oil saturations from the electrical tomograms with the CT images shows good agreement.
The possible application of other types of sensors and how they may be used in conjunction with electrical measurements is also discussed. Our results show that it may be possible to make measurements of porosity and fluid saturations down-hole, directly behind the bit, using the proposed method.
Optimization of Nonconventional Well Type, Location and Trajectory
Authors: Yeten Burak , Durlofsky Louis J. , Aziz Khalid 
Published: December 2007

Abstract
The determination of the optimal type, location and trajectory of a nonconventional well is very challenging. The problem is more complicated than other well optimization problems because of the wide variety of possible well types (i.e., number, location and orientation of laterals) that must be considered. In this paper, a general methodology for the optimization of nonconventional wells is presented. The optimization procedure entails a Genetic Algorithm applied in conjunction with several acceleration routines that include an artificial neural network, a hill climber, and a near-well upscaling technique. The overall methodology is then applied to a number of problems involving different reservoir types and fluid systems. It is shown that the objective function (cumulative oil produced or net present value of the project) is always increased relative to its value in the first generation of the optimization, in some cases by 30% or more. The optimal well type is found to vary depending on the reservoir model and objective function. The effects of reservoir uncertainty are also included in some of the optimizations. It is shown that the optimal type of well can differ depending on whether single or multiple realizations of the reservoir geology are considered.
A Model for Analysis of Injection-Well Thermal Fractures
Authors: Slevinsky B. A. 
Published: December 2007

Abstract
The performance of water injection wells in deep, warm reservoirs is usually dominated by thermally enhanced fracturing of the formation. Modern pressure and rate monitoring data for these injection wells allows the fracturing performance of the wells to be observed on a continuous basis. A simple analytical model for thermal fracture growth has been developed, by coupling equations for fracture growth and fluid leak-off from the fracture. The empirical equation form allows the observed data to be analyzed to determine the timing and extent of fracture growth, and degree of fracture face plugging. As well, the equation form has lead to development of a fracturing index, which can be used as a surveillance tool to determine the state of fracture growth in an injection well.
Once calibrated for a field or area, the model can be used to predict continued extension of fractures with time and injection. An example of analysis of an offshore injection well illustrates application of the model to real-time surveillance. The model has also been used to design new injection wells including the attached thermal fractures, aiding production engineering well equipment design, and reservoir simulation to evaluate well placement for optimum performance. The approach is new, pragmatic, and does not require coupled geo-mechanical and thermal simulation models.
SPE Paper 20741 states: "A solution for fracture growth in terms of detailed fracture-volume balance (as is often applied to hydraulic stimulation) is not a natural or feasible approach."
The method outlined in this paper shows that it is not only feasible, but leads to development of an empirical equation form which allows improved understanding of well performance and ability to forecast future behaviour.
Deep Water Real Options Valuation: Waiting for Technology
Authors: Rutherford Steven R. 
Published: December 2007

Abstract
This paper describes a real options valuation of a deepwater development opportunity in case history format. When valued using today's development costs, the project is economically challenging. However, new subsea development technologies that are expected to become available over the next 5 to 10 years should dramatically enhance the economics of the project. The main economic impact of these technologies is through enhanced production rates and increased peak production plateaus though reduced CAPEX benefits may accrue as well.
The real options valuation employs a "compound sequential option" approach implemented using a Dynamic Decision Tree technique. The first component of the compound option corresponds to the exploration phase of the project. During this phase, exploration and delineation drilling is undertaken to resolve the uncertainty associated with the size of the reserves. At the end of the exploration phase the development team has two alternatives to choose from. The project can be developed using conventional technology, if economically viable, or an option to wait and develop using new technologies can be exercised. The wait for new technology option is the second component of the compound option. During the waiting phase uncertainty concerning the enhanced productivity derived from the new technologies is resolved. The flexibility associated with these development alternatives significantly increases value when compared to a conventional NPV analysis of the project. The results presented in this paper are directly applicable to other deepwater valuations and similar types of valuations involving anticipated new technology developments.