bluuebunny/crossref_metadata_2025_split huggingface dataset:
An Investigation of the Effect of Oil Composition on Heavy Oil Solution-Gas Drive
Authors: Tang G. -Q. , Leung T. , Castanier L. M. , Sahni A. , Gadelle F. , Kumar M. , Kovscek A. R. 
Published: December 2007

Abstract
Solution-gas drive has been implemented successfully for some heavy-oil reservoirs in Canada and Venezuela since the 1980's. Nevertheless, the mechanisms of heavy oil-solution gas drive remain unclear. The objective of this study is to probe the phenomenon experimentally. To this end, a series of depletion experiments were conducted that employ heavy crude oils from two different fields in Venezuela and two viscous mineral oils. The experiments were conducted at reservoir temperatures for crude oils and room temperature for mineral oils with similar viscosity. The sandpack is made up of Ottawa sands with a porosity of about 20-30% and permeability of roughly 2.7-5 Darcy. The sandpack is placed in a specially designed aluminum coreholder that allows visualization of gas phase evolution during depletion using X-ray computed tomography (CT). In addition, a visualization cell with a window size of 5 x 40 x 0.05 mm (width × length × thickness) was installed at the outlet of the sandpack to monitor the flowing-gas-bubble behavior versus pressure. Bubble behavior observed at the outlet corroborates CT measurements of in-situ gas saturation versus pressure. Importantly, these results help us to understand the gas flow pattern inside the sandpack.
Results show that solution gas-drive is effective even at reservoir temperatures as high as 80°C. Oil recovery ranges from 12-30% OOIP; the higher the depletion rate, the greater the recovery rate. Secondly, both depletion rate and oil composition affect the size of mobile bubbles observed. At a high depletion rate (0.035 PV/hr), a foam-like flow of relatively small pore-sized bubbles dominates the gas and oil production of both crude oils. Conversely, at a low depletion rate (0.0030 PV/hr), foam-like flow is not observed in the less viscous crude oil; however foam-like flow behavior is still found for the more viscous crude oil during the early and middle periods of gas and oil production. No foam-like flow is observed for the mineral oils. Third, intermittent gas-bubble flow causes the produced gas-oil ratio (GOR) to fluctuate over time. Fourth, CT images show that the gas saturation distribution along the sandpack is not uniform at our test conditions; high gas saturation at the outlet is observed for virtually all oils. Away from the outlet, gas saturation is also heterogeneous and apparently related to heterogeneities within the pack. As the pattern of produced gas switches from dispersed bubbles to free gas flow, the distribution of gas saturation becomes even more heterogeneous. This indicates that a combination of pore restrictions and gravity forces significantly affects free gas flow.
Experimental Investigation of Oil Drainage Rates in the Vapex Process for Heavy Oil and Bitumen Reservoirs
Authors: Karmaker Kulada , Maini Brij B. 
Published: December 2007

Summary
Vapor extraction (Vapex) process is an emerging technology for viscous oil recovery that has gained much attention in the oil industry, as it appears to be superior to the currently used thermal based recovery methods. The process has potential to succeed even in some problematic scenarios, such as reservoirs with an overlying gas cap, bottom water table, high water saturation, low thermal conductivity, thin pay zone, etc. However, the oil production rates in the field as predicted by previous researchers are too low to make this process attractive for field implementation. Their predictions are based on the results from physical model experiments and the scaling-up method that hypothesizes that the oil recovery rate in the Vapex process should be proportional to the square root of the reservoir transmissibility. This scaling-up theory ignores the role of dispersional mixing between solvent vapors and in-situ oil during the gravity drainage process in porous media.
The objective of this study was to reinvestigate the oil drainage rates and thereby examine the scale-up method in the Vapex process. An extensive experimental study was carried out with three different physical models of varying sizes that were partially scaled. These models were packed with the sand-grains of three different size distributions. The Vapex experiments were carried out to investigate the effects of laboratory model size and sand-grain size on the observed performance of the Vapex process. The results show that much higher oil rates in field processes are possible compared to those predicted by previous investigators based on the results from Hele-Shaw cell experiments and the available scale-up procedure.
A New Planning Tool for Smart Fields Evaluation
Authors: Lund Bjørnar , Kolnes Øyvind , Michelsen Finn Are , Halvorsen Ivar J , Nyhavn Fridtjof 
Published: December 2007

Abstract
Downhole Instrumentation And Control Systems enable optimization of Production and Reservoir Management. This paper focuses short-term Production Optimization of a well pair (injector and producer) with expected sand production problems. Simulations show that profit could be gained.
The simulations are based on simplified models (assures high speed computations, a requirement in stochastic numerical uncertainty handling) for flow through wells and reservoir, and a volumetric sand production model. Although no stochastic uncertainty simulations are reported here, the effort of simplifying models is motivated by this. Cases with and without optimization are compared. Additionally, one case with a stuck valve indicates the sensitivity of equipment failures. We also discuss interactive use of the software as a learning tool for improved understanding of reservoir properties and behavior.
Production Diagnostic Analyses with Incomplete or No Pressure Records
Authors: Poe B. D. 
Published: December 2007

Abstract
This paper discusses the use of quantitative production diagnostic analyses for unfractured vertical wells and finite-conductivity vertically fractured wells that have partial or entirely absent well flowing pressure records corresponding to the flow rate data. The production rate data are almost always available for a production performance analysis of a well, since the hydrocarbon production relates directly to the revenue from the well and often the water production data is available since it is a production or operating cost. However, the corresponding flowing pressure data are often incomplete, or in the case of artificially lifted wells, the flowing pressure data are generally not available.
The diagnostic analyses considered in this paper are complimentary to the decline curve analysis matching procedure reported in an earlier publication that utilized an effective convolution analysis that does not require that the flowing pressures be known for each of the production data points in the production history of a well. The use of diagnostic analyses procedures in conjunction with the log-log production decline curve analyses can dramatically reduce the uniqueness problems often encountered in production decline analysis type curve matching procedures using the effective convolution analysis methodology.
Stochastic Sensitivity Analysis: Or What Happened to my Tornado Plot?
Authors: Mudford Brett , Kuch Suzanne 
Published: December 2007

Abstract
As the upstream E&P industry moves into riskier environments and the competition for capital becomes tighter there is an increasing push to carry out more sophisticated analysis that includes the effects of uncertainty and risk. Traditionally, much economic analysis has focused on a mean case, or few cases that capture high, medium, low and failure outcomes. Sensitivity analysis is then used to assess the impact on economic value as the inputs, such as recoverable volumes, production rates, operating expense and capital are varied independently of one another. The results from this type of analysis are often displayed as a tornado diagram showing the variation in output as a function of variation in the input. The standard tornado diagram provides a good characterization of project drivers, provided the inputs are independent. For most realistic projects the fundamental assumption of independence between inputs is violated, and the conclusions that are drawn from the standard sensitivity analysis may be incorrect.
In this paper we will carry out a detailed sensitivity analysis of a typical deepwater Angola project. Many of the geoscience and engineering inputs for the economic analysis of this project have distributions, and there are also a large number of dependencies between the various inputs in the model. We will derive stochastic tornado plots that are equivalent to the familiar tornado plots described above. In addition, we will show how stochastic spider plots can be developed that provide a great deal of information on project drivers and sensitivities. In this paper we will set out a range of techniques and tools that can be used to analyze stochastic models to determine economic drivers under conditions of uncertainty and dependency, without having to make unrealistic assumptions of independence between project inputs, as is common today.
Development and First Application of Bistable Expandable Sand Screen
Authors: Hackworth Matthew , Johnson Craig , Heiland Juliane , McClurkin Joel , Eubank Don , Kemp Martin , Schetky L. M. , Smith Philip S. 
Published: December 2007

Abstract
Sand control in an open hole typically results in risky completions, especially in weak or unconsolidated formations. Stand-alone screen completions present the risk of wellbore collapse and screen erosion, while gravel packing involves time-consuming and complicated pumping operations. Although expandable sand screens have recently become available to provide the best of both worlds, fast installation and wellbore support, design constraints limit their application. Wellbore conformance, expansion loads, and connection integrity have been critical issues with these types of screens. Where successful applications have been found, improved production with lowered drawdown have been typical.
Extensive research and finite element analysis have led to the development of bistable expansion cells. These cells have minimal plastic deformation during expansion and exhibit a hysteresis -like behavior. The specific cut pattern can open with relatively low expansion force, and then resist higher-level collapse loads. Due to the low plastic strain levels, bistable cells are compatible with any common oilfield material, achieving expansion ratios as high as 1.6 times the original screen diameter. This paper will cover the design, development, and testing of an expandable sand screen using bistable cell technology. In addition, the design and development of the proprietary expandable connection will be presented. The testing presented covers a wide range of structural integrity, expansion, sand retention, mudflow, and geomechanical tests performed on the screen, base pipe, and connection.
In late 2002, the first bistable expandable sand screen was deployed in a 4,400-ft water injection well in west Texas. The compliant expansion tool deployed the screen in one trip at speeds exceeding 1,800 feet per hour with set-down loads of less than 20,000 pounds.
Prediction of and Effective Preventative Solution for Annular Fluid Pressure Buildup on Subsea Completed Wells-Case Study
Authors: Loder Toni , Evans Jason H. , Griffith James E. 
Published: December 2007

Abstract
Trapped fluid commonly occurs in subsea completed wells when casing annuli attains a closed volume; for example, a subsea wellhead set and cement top inside the previous casing shoe. When the well is placed on production and wellhead temperature increases, the trapped fluid, usually drilling mud and spacer, expands. This thermal expansion significantly increases the annular pressure. Depending on the initial wellhead conditions, the trapped fluid's temperature could increase in excess of 83ºC (150º F) over ambient conditions. Laboratory testing indicates that trapped water- or synthetic oil-based fluids can increase in pressure (greater than 69 MPa or 10,000 psi) well above the casing collapse pressure if the well experiences such a differential temperature cycle.
An effective solution offered in previous literature is the incorporation of a compressible spacer in the cementing process. The compressible spacer is trapped in the closed annulus and can greatly reduce the pressure buildup if fluid expansion occurs. Deepwater operators have used this solution in a casual manner because the margin for error is somewhat large. However, in shallower subsea completed wells (less than 300m or 1,000 ft water depth), the margin of error is greatly reduced. This reduction motivates the need to find the optimal compressible spacer volume based on lower final hydrostatic pressures and appropriate volume to compensate for fluid expansion. Operationally, finding these optimal volumes helps reduce the chance of a kick condition or compressible fluid being circulated into the riser system.
This paper presents a method for calculating the optimal amount of compressible spacer to be trapped in a well's annulus. The calculations consider the expansion of the trapped fluid based on annular volume and fluid type(s). The paper also presents previously published data on various water and synthetic oil-based fluids and an example of the calculations in well conditions for an east-coast Canadian subsea well.
The Economic Analysis of a Two-Rig Approach to Drill in Deepwater Gulf of Mexico Using Dual Gradient Pumping Technology
Authors: Hariharan P. R. , Judge Robert A. 
Published: December 2007

Abstract
Drilling the upper hole section of wells in deepwater is conventionally done riserless with returns taken to the seabed in a process known as "pump and dump". The depth to which a hole can be drilled using this method is limited by the presence of drilling hazards (shallow water/gas) as well as the economics of not recovering drilling fluids. Using pumps developed for dual gradient drilling operations and taking the mud returns along with the drilled cuttings to the rig rather than at the seafloor can have significant impact on the costs of drilling the well. Additionally, utilizing a mud pump at the sea floor creates possibilities for managing the bottom hole pressure by varying the inlet pressure of the subsea pump. The ability to vary annular pressure allows management of potential shallow water flow situations, creating opportunities to drill through such zones and set the conductor casing, typically 20″ in the Gulf of Mexico (GOM), deeper. Setting the conductor casing deeper can significantly impact well economics, ranging from the saving of a complete size of casing string to larger final borehole completions.
To assess the viability of a solution based on using subsea mud pumps to drill the upper hole sections, an economic study and analysis of the costs of drilling deepwater wells in the GOM was carried out. This paper discusses the results and the economic benefits based on a probabilistic risk-based cost analysis comparing cost data of actual wells drilled in the Gulf of Mexico to wells that were modeled using the alternate drilling method. In the modeled wells, two rigs were used, one to drill and set the conductor casing only, followed by another rig to complete the well. For this paper, the drilling costs for the 2-rig approach are compared to the costs of conventionally drilling the same well. Details of the analysis, the modeling process and the assumptions are discussed. The analysis showed that significant savings in well costs are possible, and on a conservative basis varied from 6 – 25% of the total well cost. The analysis also showed that apart from cost savings, using such a 2-rig arrangement could also aid in mitigation of risk while deploying new technologies by transferring the risk to the first rig used solely for drilling the upper hole sections.
Accounting for Interpreted Well Test Pore Volumes in Reservoir Modeling
Authors: Zhang Linan , Cunha Luciane B. , Deutsch Clayton V. 
Published: December 2007

Abstract
Optimal reservoir management requires reliable reservoir performance forecasts with as little uncertainty as possible. There is a need for improved techniques for dynamic data intergration to construct realistic reservoir models by using geostatistical techniques. This paper gives a method to create porosity models that honor interpreted pore volumes from well test data. Well porosity data, seismic data and well test results are integrated in sequential simulation. Seismic data is modified iteratively until the co-simulated porosity matches the interpreted well test pore volume. A number of examples are shown.
Effect of Scale Up and Aggregation on the Analysis of Interference Tests
Authors: Rajagopal Raghavan , Roesler Ralph R. , Tureyen O. Inanc 
Published: December 2007

Abstract
The objectives of this paper are to demonstrate the impact of detailed and small-scale heterogeneities upon interference tests. Specific issues encountered when interference tests are analyzed in reservoirs with complex geological properties are discussed. These issues relate to questions concerning the use of low-resolution models, the degree of aggregation, methodology of scale up and the reliability of conventional methods of analysis.
Estimation of Storativity Ratio in a Layered Reservoir with Crossflow
Authors: Al-Ajmi N. M. , Kazemi H. , Ozkan E. 
Published: December 2007

Abstract
This paper presents a practical method to estimate the storativity ratio of a layered reservoir with cross-flow from pressure transient data. The method uses an analytically derived formula for the storativity ratio in terms of the separation between the two semi-log straight lines on pressure versus log-time plot. Knowing the storativity ratio from a well test, individual layer properties may be estimated if the layer flow rates are available from production logs. Demonstrations of the method to estimate the storativity ratio and individual layer properties are presented by examples. Comparison of the results with those obtained from the existing techniques is also provided to highlight the accuracy of the proposed technique.
Modeling Imbibition Capillary Pressure Curves
Authors: Adams Stephen 
Published: December 2007

Abstract
Although spontaneous imbibition capillary pressures are relevant in all reservoirs having undergone or undergoing gravity stable water displacement, they are not commonly measured nor considered for reservoir modelling. Imbibition is particularly important when establishing initial hydrocarbons in place for reservoirs already having residual hydrocarbon columns prior to production commencement.
As part of a saturation-height study, an empirical model relating imbibition capillary pressure curves to their drainage precursors was created. Drainage saturation-height functions could then be used to create imbibition equivalents based upon the saturation history of the reservoir rock. Calibration was carried out using laboratory measurements of both drainage and imbibition capillary pressure curves.
This "imbibition from drainage" (IFD) model was verified against log derived water saturations from wells in the initial study area. The match was excellent in those wells considered to have reliable petrophysical evaluations. The IFD model was even able to describe imbibition capillary pressure curves for sections of reservoir in drainage transition zones prior to the commencement of water imbibition. The model has since been further verified in other hydrocarbon accumulations found in different basins.
The IFD model developed represents the first publication of a technique for creating meaningful spontaneous imbibition capillary pressure curves and imbibition saturation-height functions through reservoirs with significant capillary transition zones. The technique should be widely used to describe water saturations in reservoirs with residual hydrocarbon columns, providing better estimates of initial hydrocarbons in place than with more commonly used drainage data. Iteration of the model also allows determination of both original and current day Free Water Level locations in systems having residual hydrocarbon columns from either leakage prior to production or from gravity controlled water sweep during production.
Realistic Assessment of Proppant Pack Conductivity for Material Selection
Authors: Barree R. D. , Cox S. A. , Barree V. L. , Conway M. W. 
Published: December 2007

Abstract
Proppant selection in hydraulic fracturing is a critical economic and technical decision that affects stimulation and field development economics. In many cases the selection is based on laboratory data from standardized API conductivity tests on clean packs at specified stress and temperature. These tests predict conductivities that are optimistic compared to observed field performance. Often a laboratory measured conductivity difference of only 5-10% is considered a significant variance when applied to the producing life of a well. The significance of these small differences, however, is often overwhelmed by other factors affecting fracture performance in the field.
The selection of a particular proppant should be based on an identifiable difference in performance under field conditions. This requires an accurate assessment of all the damage mechanisms that can and do occur during fracturing and their impact on final conductivity. This paper outlines the primary damage mechanisms and their effect on conductivity, fracture cleanup and ultimate stimulation response. The expected variance in laboratory measurements of conductivity is also quantified.