bluuebunny/crossref_metadata_2025_split huggingface dataset:
Economic Evaluation of Treating Oilfield Produced Water for Potable Use
Authors: Patrick B. , Tsang P. E. , Christopher J. , Martin P. E. 
Published: December 2007

Abstract
Conventional opinion has often viewed produced water as a byproduct from oil production. Disposal of this water is an expense every treatment facility must contend with as long as their wells continue to produce. This issue can become a serious logistical or environmental problem for fields with limited disposal capacity or that generate produced water with poor water quality.
Instead of discarding the water as waste, advances in membrane water treatment technology can allow economical treatment of water for potable consumption. Placing this water to productive use may not completely eliminate daily wastewater disposal. However, it will drastically reduce the disposal volume, possibly freeing up other resources. This concept shifts the paradigm for produced water, transforming its image from what seemingly is a costly waste to possibly a valued commodity.
This paper will present a conceptual design for a 50,000 BPD integrated membrane filtration plant capable of handling typical oilfield produced water. Included will be an evaluation of capital and operating & maintenance costs. A discussion on the marketing potential for this water as a new potable or irrigation water source will also be presented by comparing its economics against conventional surface water or seawater desalination treatment.
Sand Erosion in Cold Heavy-Oil Production
Authors: Yalamas T. , Nauroy J.-F. , Bemer E. , Dormieux L. , Garnier D. 
Published: December 2007

Abstract
Ensuring quantitative prediction of eroded sand volume is a major challenge for companies, which seek to conduct effective sand management. This is particularly a key point for Cold Heavy Oil Production With Sand.
IFP has been studying the geomechanical aspects of heavy oil cold production for several years from both the experimental and theoretical points of view [Deruyter & al., 1998], [Nauroy J.-F., 1999]. While experimental studies of sand erosion are mostly based on linear flow through cylindrical cells [Tremblay & al., 1995], IFP has designed a special oedometric cell to simulate a radial flow around a well drilled in an unconsolidated sand reservoir.
The current device allowed to observe two types of erosion figure under CT-scan, defined as "cavity" or "spread erosion". Two main key parameters governing erosion have been identified.
Dimensional analysis shows that CHOPS in situ conditions should lead to a "cavity" type erosion. Various theoretical models describing sand erosion and mixed sand/fluids flow have been investigated. An algorithm allowing to predict the formation of a cavity has notably been defined and already validated for a 1D numerical modeling. A 2D numerical modeling is in progress.
Effects of CO2 and CH4 Addition to Steam on Recovery of West Kozluca Heavy Oil
Authors: Bagci A. S. , Gumrah F. 
Published: December 2007

Abstract
The physical models, cylindrical tube (1-D) and rectangular box (3-D), were used to examine the effects of simultaneous injection of CO2 and CH4 together with steam on the recovery of 12.4 °API gravity heavy oil mixed with unconsolidated limestone.
The results of 18 experiments showed that gas-steam injection was a promising technique. Gas/steam ratio was found to be a significant factor among the studied variables in heavy oil recovery. The optimum gas/steam ratio that maximized the recovery was about 9.4 cc/cc for both steam-CO2 and steam-CH4 processes in one-dimensional model. It was 8.7 cc/cc for steam-CO2 process in 3-D model.
At 1.5 pore volumes of steam injected; the oil recoveries were 66.5 % of OOIP for steam-CO2, 60.4 % of OOIP for steam-CH4 and 50.9 % of OOIP for steam alone tests in 1-D model and they were 49.9 % of OOIP for steam-CH4, 36.2 % of OOIP for steam-CO2 and 21.7 % of OOIP for steam alone tests in 3-D model. The lower residual oil saturations were obtained in gas-steam injection tests, compared to the values obtained with steam alone.
The injected non-condensable gas created a permanent gas phase across the top of the model therefore heat arrived to the producing well earlier than steam alone test. The depression of steam temperature was also observed due to the presence of non-condensable gas.
Expanded Uses of Nitrogen, Oxygen and Rich Air for Increased Production of Both Light Oil and Heavy Oil
Authors: Kuhlman Myron I. 
Published: December 2007

Abstract
Both light-oil air injection (LOAI) and nitrogen injection have received considerable attention recently due to several successful LOAI projects and the building of massive nitrogen generation plants for offshore EOR. This paper explores the advantages of combining the best of both technologies via cogeneration of nitrogen and rich air for use in adjacent reservoirs.
Rich air (30% to 40% oxygen) can be an alternative to carbon dioxide injection just as air injection is generally practiced where carbon dioxide is not available. Rich air is the byproduct of nitrogen generation and has approximately the same price as nitrogen, yet it will recover more oil because of the higher solubility of the carbon dioxide that is produced by in-situ oxidation of the oil.
Not only can the rich air be used for light-oil production, but also it can be a more efficient way to produce energy from heavy-oil through wet combustion in deeper reservoirs. Examples contained herein illustrate how nitrogen and rich air can be used in both light- and heavy-oil reservoirs.
Disposal of Carbon Dioxide, a Greenhouse Gas, for Pressure Maintenance in a Steam-Based Thermal Process for Recovery of Heavy Oil and Bitumen
Authors: Law David H.-S. 
Published: December 2007

Abstract
The world is moving towards a carbon constrained economy and there would be pressure to reduce greenhouse gas (GHG) emissions. The steam-based thermal processes are energy intensive and hence, high carbon dioxide (CO2), a greenhouse gas (GHG), emissions. There are potentials for the reduction of CO2 emissions by capturing and disposal of CO2 for pressure maintenance during the later stage of these thermal operations. This paper describes the numerical investigation on the feasibility of using CO2 for pressure maintenance during a steam-assisted gravity drainage (SAGD) wind-down process in an Athabasca bitumen reservoir in Northern Alberta, Canada.
It is found that SAGD wind-down process with CO2 injection is feasible although oil recovery performance is slightly sacrificed. The oil recovery performance during the wind-down period with pure CO2 injection is slightly better than those with other gas injections such as flue gas (i.e., a mixture of nitrogen (N2) and CO2) and pure N2 mainly because CO2 acts as a solvent in reduction of the bitumen viscosity.
From a GHG storage point of view, CO2 storage capacity of approximately 2 × 107 sm3 (or 37,244 tonne) in a single Athabasca-type SAGD pattern with dimensions of 100 m wide, 500 m long and 25 m thick can be achieved. CO2 balance indicates that CO2 stored during SAGD wind-down processes is less than the CO2 emitted from steam generation during the initial SAGD period. However, "CO2 credit" in the order of 10,000 tonne can still be claimed in a single SAGD pattern because using CO2 as steam substitute during the wind-down process results in less CO2 emission compared to continuously operating the SAGD process.
Recently, numerical prediction in this study has been validated qualitatively by the experimental observations of SAGD pressure maintenance from a low-pressure/low-temperature CT experiment and a high-pressure/high-temperature 2-D experiment conducted at the Alberta Research Council (ARC).
Characterization of Water Injection in Low Permeable Rock Using Sandstone Micro-Model
Authors: Sun Wei , Qu Zhihao , Xian P. R. C. , Tang Guo-Qing 
Published: December 2007

Abstract
Visual micro-model technology has been applied to investigate multiphase flow in porous media because it allows watching the fluid flow clearly under a microscopy. However, most micro-models are made up using glass media. A sandstone micro-model (SMM) manufactured from thin sandstone chip directly was introduced and applied in the study of water injection in low permeable rock. To make the sandstone micro-model, a selected core plug was carefully machined into a chip with a thickness of about several hundred micrometers. The sandstone chip was then sandwiched in two glass plates using a specific cementing process. The main improvement for this kind of micro-model is that it preserves the original pore structure, clays, cements, and pore surface properties.
Total 18 sandstone micro-models with permeability from 1-10 md were used for displacement test at room temperature. The results show that the water injection in the weakly oil-wet to neutral-wet sandstone micro-model is dominated by the injection pressure. At low injection pressure, the water can only enter large pores that have a high conductivity. Large amount of pores is not flooded by water. When the injection pressure was increased, water is forced into some small pores to displace oil. However, heterogeneous properties of the porous media can cause a bypass flow, resulting early water breakthrough and low water displacement efficiency. We also found that oil recovery is proportional to the permeability of the model, suggesting the pore conductivity is the key to the water injection efficiency.
This study also shows that sandstone micro-model provides visual and realistic results that reveal the microscopic mechanism of water injection the target reservoir. However, visibility is less compared to a glass micro-model. Thus, the combined results from both sandstone and glass micro-model are more valuable.
A Study of Heavy Oil Solution Gas Drive for Hamaca Field: Depletion Studies and Interpretations
Authors: Satik Cengiz , Robertson Carlon , Kalpakci Bayram , Gupta Deepak 
Published: December 2007

Abstract
We present results of a systematic study performed to investigate heavy oil solution gas drive process for Hamaca field in Venezuela. The ultimate goal of this study is to provide the data needed for Hamaca reservoir simulation studies. The study included a series of rock and fluid property measurements, and several carefully performed depletion experiments. Supplemental experiments using PVT cells and ideal porous media were also conducted to aid in the analysis of the depletion experiments.
For this study, single-phase live oil samples from Hamaca Field were used. Fluid characterization tests were performed, including GOR, viscosity, density, compositional measurements and other PVT experiments. Average properties of the live oil used were GOR of 96 scf/STB, bubble point pressure of 1020 psia at 125 °F and viscosity of 1650 cP at reservoir conditions. In addition, several flow experiments were conducted using the live oil to elucidate so-called "foamy oil" behavior by obtaining rheological data at above and below thermodynamic bubble point.
Depletion experiments were conducted at reservoir conditions using field core and oil samples from Hamaca Field. Tests were performed at constant depletion rates from 0.25 psi/hr to 43 psi/hr to cover the flow regimes, which may be occurring at different distances from the wellbore. A CT scanner was used to observe the distribution of gas saturation at various points during the depletion tests. Critical gas saturation values ranged from 8 to 15%. Depletion rate did not have significant effect on the critical gas saturation. Gas-oil relative permeability curves were calculated using a new technique based on effluent density measurements done during the depletion experiment. Calculated gas relative permeability curves appeared to be suppressed, in the range of 10−10 to 10−5.
Applications of dynamic gridding to thermal simulations
Authors: Christensen J. R. , Darche G. , Déchelette B. , Ma H. , Sammon P. H. 
Published: December 2007

Abstract
This paper describes a new technique to decrease the computational times of thermal simulations. Effectively, thermal processes are based on the displacement of a thermal front (combustion front, steam chamber interface), around which most fluid flows will take place. Thus, we propose a dynamic gridding approach, to keep a fine scale representation around the thermal front, and a coarser grid away from the front, thus leading to cheaper computations.
We will first describe the principles of this dynamic gridding. Simulations will start with an original fine grid, but will reamalgamate its cells, while keeping some regions (for example around wells) always finely gridded. The gridding will then identify the moving front through large gradients of specific properties (temperatures, fluid saturations and compositions). In the front vicinity, it will de-amalgamate the originally amalgamated cells, and later on re-amalgamate them once the front has passed. Amalgamated cells are assigned up-scaled properties, this upscaling being based upon classical averaging techniques.
We will illustrate this dynamic gridding technique with simulation examples, as it has been successfully implemented in a thermal simulator, STARS, a product of Computer Modelling Group Ltd (CMG). Using examples on combustion and SAGD simulations, we will show that it can divide the CPU time of thermal simulations by a factor of 2 to 3, without loss of accuracy.
Subsurface Challenges in Reservoir Modeling for Hamaca Project
Authors: Acharya U. K. , Kent A. , Betancourt D. , Waite M. W. , Tankersley T. , Johansen S. , Robertson C. 
Published: December 2007

Abstract
Hamaca project is a large resource base producing Extra Heavy Crude Oil from the Orinoco belt of Venezuela. The project is operated by Petrolera Ameriven, an operating agent owned by ConocoPhillips, ChevronTexaco, and Petróleos de Venezuela, S.A. (PDVSA). Primary production started in September 2001 from a few horizontal wells; development drilling will continue over the next 34 years to maintain a production plateau of 190,000 bopd of cold production.
The subsurface challenges involve building a representative reservoir model on a very fine scale to honor a very heterogeneous system over a large area, wide variations in temperature across the field and their effect on oil viscosities, vertical and lateral variations in oil properties and fluid pressure, upscaling the model sufficiently to be capable of running the dynamic model on available computer hardware and software. The model is calibrated using the short Hamaca production history (less than 2 years), and is then used to predict the performance of development scenarios containing hundreds of horizontal wells to be drilled in the future.
The paper discusses the challenges of selecting suitable modeling methodologies, of matching the limited historical production data, of modeling the influence of production in adjoining fields, of populating the model with hundreds of wellpaths for future horizontal wells, and of conducting sensitivity analyses to evaluate the effect on production forecasts of uncertainties in some key reservoir parameters.
Characterization of Rock Heterogeneity Using Fractal Geometry
Authors: Li Kewen 
Published: December 2007

Abstract
There have been three main models applied to infer fractal dimensions of reservoir rock from capillary pressure curves measured by mercury intrusion. In this study, fractal dimension was used to characterize the heterogeneity of rock quantitatively. The three fractal models were derived theoretically and found to be interrelated. Capillary pressure curves of different rock samples were measured using a mercury intrusion technique. The values of fractal dimension were calculated using the three fractal models and the results were compared. The values of fractal dimension calculated from two models were almost the same and ranged from 2 to However the fractal dimensions calculated using the other model were different and ranged from 1 to 2. It was found that the Brooks-Corey capillary pressure model did not work for all of the core samples studied but the fractal models work satisfactorily in all cases. The fractal approach was verified qualitatively using frequency graphs of pore size distribution of the rock samples.
Application of Stress-Dependent Rock Properties in Reservoir Studies
Authors: Vassilellis George D. , Jones Stanley C. 
Published: December 2007

Abstract
Jones1 previously developed smooth, non-linear equations for fitting permeability, PV, or porosity data at multiple net hydrostatic confining stresses. The present paper supplements the original by illustrating steps required to convert these measurements into curves for uniaxial strain conditions. The concepts of specific pore volume and specific bulk volume are introduced. These dimensionless values are independent of sample size, and are more useful than pore volume or bulk volume when comparing samples. The latter is useful for subsidence calculations.
An averaging technique for the reduction of normalized PV, porosity, or permeability with increasing net stress is also demonstrated for samples from a particular lithology. Samples that do not fit the general trend are easily identified, and can be excluded from averaging if desired. Studies in California reservoirs suggest that stress-related permeability reduction correlates with corresponding reduction in porosity better than permeability correlates with porosity.
A Simple Model for Predicting Heat Loss and Temperature Profiles in Thermal Injection Lines and Wellbores With Insulations
Authors: Guo Boyun , Duan Shengkai , Ghalambor Ali 
Published: December 2007

Abstract
Accurate predictions of heat loss and temperature profile in thermal injection lines and wellbores are essential to designing and evaluating thermal operations. Although some sophisticated computer packages are available for such purpose, their accuracies suffer from numerical treatments and model-building skills of inexperienced users. A simple-and-accurate analytical heat transfer model is highly desirable.
This paper presents three analytical heat transfer solutions for predicting heat loss and temperature profiles in thermal-insulated flow conduits. The three solutions consist of one steady state flow solution and two transient flow solutions. The two transient flow solutions are for start-up mode and flow rate change mode (shutting-down is a special mode where the flow rate changes to zero). Capability of the analytical model is investigated using a data set that is representative to a typical case of liquid flow in a small-diameter thermal pipeline. An application example is illustrated where the model-calculated temperature profile is used to identify the possible interval of asphaltene deposition in an oil well. The mathematical heat transfer model can also be used for predicting temperature distribution in offshore pipelines.
Steamdrive Stability in High Porosity Rock
Authors: Hoffman B. Todd , Kovscek Anthony R. 
Published: December 2007

Abstract
Steamflood displacement is considered to be stable, as compared to other gasflooding techniques. Stability on the microscopic and core scale is thought to lend stability to steam movement on the reservoir scale. High mobility displacing agents tend to "finger" beyond the front, but this effect is suppressed for steam by condensation within the finger as steam contacts lower temperature reservoir. Heat transfer from the steam to the surrounding connate water, oil, and rock is the primary mechanism to ensure stability. Because most reservoirs have a significant proportion of rock (70%-80%), there is sufficient thermal mass to cool any steam fingers. However, when the porosity is high, there is less rock to dissipate heat; therefore, less suppression of viscous instabilities. Depending on the porosity and other reservoir properties, the typical assumption of stable steamflood displacement may not be valid. Initial aspects of this work use analytical methods to examine frontal stability in high porosity rocks. Analytical methods indicate stable steam fronts for typical reservoir properties, but they also predict unstable displacement in high porosity rock.
The second portion of this work uses pattern level thermal simulation to study the stability of steam drives in high porosity rocks. Two different permeability models (an isotropic model and a thief model) are compared at three porosities (25%, 50% and 70%). Low rock thermal conductivity is shown to reduce the suppression of the steam fingers. More importantly, the simulation results show that as the porosity increases the stability does decrease. This is exemplified by shorter breakthrough times for the higher porosity models. While the stability of a steam front does decrease, the difference is likely not very significant, around a 20% reduction in breakthrough time, compared to other aspects. For example, reservoir heterogeneity has a much greater impact on breakthrough time than the relatively unstable displacement front associated with high porosity rock.
New Fluid Technology Improves Well Productivity in the Western 31S Stevens Oil Zone in the Elk Hills Field
Authors: Agiddi David , Davenport Brent , Hernandez Helver , Lockman Rusty 
Published: December 2007

AbstractThis paper presents a comparative well study performed in the central California Elk Hills field, Western 31S (W31S) Stevens Oil Zone. Stimulation of the W31S Stevens Oil Zone using hydraulic fracturing with conventional polymer fluids is compared with the use of a new viscoelastic high performance fracturing fluid (HPF).The field development of the W31S zone was initially completed with conventional fracture-stimulated treatments containing borate crosslinked guar polymer and encapsulated oxidizing breakers. Although a positive production response was observed, additional production improvement was desired. Post-fracture tracer logs indicated that improvements could be made by achieving better net fracture height coverage. In addition, post-fracture acidizing treatments indicated that the fracture fluid polymer had damaged the propped fracture conductivity.Recent development in fluid technology has resulted in the introduction of a unique, patented fracturing fluid that provides the following benefits: Less damaging to the formationExcellent proppant transportability, resulting in improved net fracture height coverageRequires no breaker additivesRecyclableThis HPF fluid was compared to conventional borate crosslinked polymers, a crosslinked CO2 foam fluid, and a high pH borate crosslinked polymer with an enzyme breaker. The case histories show better production rates with the new HPF fluid. Also, despite very robust and stable rheological properties during pumping, this new fluid returns to its original viscosity shortly after closure, with no internal breakers. The unique properties of this fluid are discussed, along with case history information, in the remainder of this paper.