bluuebunny/crossref_metadata_2025_split huggingface dataset:
Understanding the Rate of Clean Up for Oil Zones after a Gel Treatment
Authors: Seright R. S. , Lindquist W. Brent , Cai Rong 
Published: April 2008

Abstract
In our previous work, X-ray computed microtomography (XMT) was used to establish why pore-filling Cr(III)-acetate-HPAM gels reduced permeability to water much more than to oil. Our results suggest that permeability to water was reduced to low values because water must flow through gel itself, whereas oil pressing on the gel in a porous medium forced pathways by dehydration—leading to relatively high permeability to oil. Those studies involved obtaining 3D pore-level X-ray images at the saturation endpoints—for example, after forcing 20 pore volumes of oil or water through the core following gel placement.
The dependence of oil permeability on oil throughput determines how long it takes for a production well to "clean up" or restore productivity after a gel treatment. Consequently, we were interested in how the gel dehydration process progresses as a function of oil throughput. This paper describes a new study where pore-scale XMT images were obtained at a variety of oil (hexadecane) throughput values after gel placement (involving a pore-filling Cr(III)-acetate-HPAM gel). For each pore in our image volume, we followed oil and water saturations as a function of oil throughput. These studies were performed both in water-wet Berea sandstone and in hydrophobic porous polyethylene. In hydrophobic porous polyethylene, oil saturations increased and gel was destroyed (presumably dehydrated) quite quickly in the smallest pores (10−6 mm3). Also, oil saturations increased and gel was destroyed quickly in the largest pores (&lt;0.005 mm3). In contrast, oil saturations rose much more gradually for the most common or intermediate-sized pores (around 10−4 mm3, the peak in the pore size distribution). The minimum in oil saturation versus pore size may result from a balance between gel dehydration by oil film growth versus gel extrusion. Presumably, during oil injection after gel placement, an oil film forms with a thickness that is about the same on all polyethylene surfaces. However, because the ratio of film thickness to pore or throat size increases with decreased pore size, gel dehydration occurs faster and more effectively in the smallest polyethylene pores, causing oil saturation to increase with decreased pore size. This effect may lose its signicance for pore sizes above 10−4 mm3. As pore size increases above 10−4 mm3, gel extrusion from the pore becomes more likely—explaining why oil saturation increased with increased pore size for the largest pores.
In contrast in water-wet Berea sandstone, increases in oil saturation occurred evenly over all pore sizes (10−6 to 0.02 mm3) for all oil throughput values. Consistent with imbibition and drainage studies performed before gel placement, oil apparently had equal access to Berea pores of all sizes, and thus uniformly dehydrated gel in pores of all sizes. Gel extrusion did not appear to be significant in the Berea pores.
Time-Lapse Seismic Used to Qualify the Drainage and IOR Strategies on the Snorre Field
Authors: Aanvik Frank , Tønnessen Randi Kristin , Aurvåg Roar , Brustad Gro Valle , Lyse Ottar , Kollbotn Lars 
Published: April 2008

Abstract
Hypothesis associated with drainage and IOR strategies are often justified theoretically or by small scale experiments. The effectiveness of reservoir development measures is therefore often uncertain.
The Snorre field is a large North Sea oil field with a thick, heavily faulted, eroded and heterogeneous (fluvial) reservoir with a complex production history with a large IOR potential. The field's economy relies on an effective IOR strategy.
A multidisciplinary time-lapse seismic interpretation project has been carried out. A workflow was designed where all data types, models, tools and disciplines were integrated in the analysis, documentation and presentation of results. 3D Geobodies populated with difference seismic amplitudes were imported in relevant software's for visualization and analysis.
The analysis has been done by a dedicated project team, while close cooperation with operational teams and applicants of the results has assured that results incorporate detailed operational experience and are properly implemented and quality assured.
Aside from producing explanations to individual seismic effects, observations were used to support or weaken hypothesis relating to the drainage and IOR strategies.
The results are integrated qualitatively in the history matching, and adjustments due to 4D information gave significant improvements. A fault seal analysis was extended with time-lapse observations. Gas injection is assumed to improve oil mobility as gas dissolves in the oil, which is not always in line with 4D observations. Gas flooding, migration and stacking (attic gas) are better understood from 4D data. Also, bypassed or unswept oil is detectable from the 4D seismic.
The results have already influenced drilling decisions and well interventions. The conclusions will also play an important role evaluating the overall drainage strategy, existing IOR strategy and upcoming IOR initiatives.
The work demonstrated how time-lapse can be taken beyond geophysics to become an integral tool in reservoir development.
Pore Scale Estimation, Up Scaling and Uncertainty Modeling for Multiphase Properties
Authors: Rustad Alf B. , Theting Thomas G. , Held Rudolf J. 
Published: April 2008

Abstract
A workflow incorporating pore space modelling, small scale heterogeneity and uncertainty modelling has been established and successfully employed in a North Sea oil reservoir. The study was performed on a heterogeneous interval of the reservoir, with water flooding as the basic recovery strategy. The geology was characterized identifying relevant scales of heterogeneity. The interval consists of hummocky cross-stratified deposits, with varying contrast and lamination. Consequently, small scale models were built capturing the laminations seen in cores at a scale interpreted to be at a representative elementary volume. Pore space reconstruction and property estimation by pore scale modelling were used to obtain realistic relative permeability and capillary pressure data for each lamination. At each stage of the workflow, a set of models was handled to account for uncertain parameters. Uncertain parameters included porosity, permeability, pore space and lithofacies geometry, and rock/fluid wettability. These parameter uncertainties propagated into uncertainty in the multiphase properties, i.e., relative permeability and capillary pressures. Steady-state multiphase upscaling was used to obtain multiphase properties representative for the geo-cellular model scale. The multiphase flow properties generated from pore scale modelling and upscaling were incorporated in an interwell-scale model with a geo-cellular grid resolution, and simulations compared with a base case model with traditional multi-phase flow properties. The updated model demonstrated altered flow behaviour and sweep, which were consistent with field observation. More precisely it showed a water override with by-passed oil in the lower parts of the model, a behaviour which was not adequately captured in the base case model. Moreover, the modified flow physics were relatively easy to implement and could be run with little additional computational cost in the full field simulation model. As the results constitute key information for reservoir monitoring and for improving oil recovery, the operational full field model was updated to include these findings.
Utilizing Acidized NH2 for Mitigating Formation Damage and Improving Oil Recovery: Case Study of Penara Field, Malaysia
Authors: Agil N. A. M. , Saaid I. M. , Ibrahim J. , Harun M. F. 
Published: April 2008

Abstract
Deposition of solid hydrocarbons such as asphaltene and wax near the wellbore and in the tubing is known to cause decline in the well production performance. Various mitigation methods such as chemical wax inhibition, thermal insulation, and coiled tubing clearance are repetitive and exhaustive. These methods could temporarily remove deposits but not prevent them from reoccurance. On the other hand, the thermo-chemical method utilizing acid-base reactions seems to be offering the most effective and simple solution to the problem. Reaction products and heat from the acid-base reactions could be utilized to dissolve and disperse wax or asphaltene deposition in addition to changing the wettability profile. The present study is to evaluate the performance of acidized amines for mitigating formation damage and improve oil recovery in the Penara Field, offshore Peninsular Malaysia. Wells in the field have been recording massive production decline of more than 5000 stb/d despite continuous treatment of pour point depressant, wax dispersant, de-emulsifier and frequent tubing clearance activities.
Physical observation and interfacial tension measurement were carried out to qualitatively and quantitatively measure the performance of the acidized amines. Improvement in the oil recovery was measured through coreflooding test. The study found that acidized amines by-products dispersed the suspended wax solid and prevented it from re-depositing after 48 hours. Thus, oil recovery increased to 51.3 % for non waxy-liquid crude and 13.0 % for waxy-gelled crude. These findings from the laboratory were further validated by production optimization using Wellflo.
The thermochemical method utilizing acidized amines is simple and yet experimentally proved to be effective in solving the wax related problem. Considering the reserve potential in the Penara Field and supported by sufficient well data, the incremental production of 22 % could be predicted.
A New Method for Vertical Leak Detection in Low to Moderate Permeability Flooded Reservoirs
Authors: Walser D. W. , Astakhov D. K. , Stanley G. R. 
Published: April 2008

Abstract
Rising commodity prices have resulted in an increase in secondary recovery projects that are associated with lower permeability reservoirs. These processes often inject fluids above the parting pressure for the duration of the life of the flood, and pressurization takes place as fluids leak off from the exposed surface area of the induced fracture into the surrounding moderate or low-permeability reservoir matrix. The primary difference between these situations and conventional flooding is that matrix fluid migration is initiating off an induced fracturing plane, as opposed to point-source initiation.
During the early history of a flood, mass-balance issues are often ignored, as average reservoir pressures are typically low, and injection rates can dramatically exceed production. As pressures rise, some localized portions of the reservoir not only can exceed virgin static pressures, but volumes near existing induced fractures can approach or equal the pressure in those fractures. When this occurs, vertical fracturing can be initiated, either above or below the reservoir, depending upon the location of the closest lower stress interval.
A new method to detect the location of vertical "leakage" has been developed. This method utilizes existing Surface Tiltmeter (STM) technologies and a new surface deformation calculation regime to zero in on volumetric changes that occur above or below the limits of the given reservoir. This method uses measured surface deformation from observed tilt to extrapolate the volumetric change at different specified depths. With a number of constraints, and using a linear geophysical model based on poroelastic equations, an inversion routine is used to find the reservoir compaction or expansion at different depths. When volumetric change best fits the measured deformation data (or tilt) at the surface, the depth and aerial location is then correlated to the area near a specific well or wells.
Economics of Field Proven Chemical Flooding Technologies
Authors: Wyatt Kon , Pitts Malcolm , Surkalo Harry 
Published: April 2008

Abstract
Chemical enhanced oil recovery technologies are field-proven methods that improve overall oil recovery. High oil prices and dropping reserves replacement has stimulated interest in these technologies, particularly for application in mature waterfloods. Depending upon the perspective of investors, the decision to proceed with an oil field project may depend upon projected: Rate of Return, Return on Investment, $/bbl of added reserves, cumulative cash flow, or combinations of these. This paper discusses chemical flooding processes, constraints on application, and presents economic impacts of: injected chemical cost, oil price, chemical concentration, oil recovery, and process time. The alkaline-surfactant-polymer technology is compared with micellar flooding and alkaline-polymer flooding. For example, a typical range of chemical costs per barrel of added oil for an Alkaline-Surfactant-Polymer project would be $3.50/bbl to $12/bbl for oil recoveries ranging from 0.2 PV down to 0.05 PV (or approximately 25% OOIP to 6.25% OOIP). Rate of Return (ROR) and payout time depends upon process rate, or pore volume per year of injection. Chemical flooding places the majority of cost over the first 50% pore volume of injection whereas, oil incremental income is delayed until the developing oil bank reaches production wells. In today's oil price environment of &gt;$40/bbl, chemical flooding technology provides significant financial returns with increased ultimate oil recoveries.
Advanced Wells: How are they Being Used and are they Creating Value?
Authors: Mitchell Anthony F. , Skarsholt Line T. 
Published: April 2008

Abstract
By December 2007 eighty three wells, in twenty three StatoilHydro operated fields in the North Sea, were equipped with advanced completions. These wells (which include vertical, horizontal and multilateral reservoir sections) typically have a completion which consists of instrumentation in combination with one or more, remotely (surface) operated, downhole valve. Levels of instrumentation varies, from the complex - with internal and external pressure and temperature gauges in several reservoir zones - to the simpler, with only one pressure and temperature gauge on top of the reservoir.
Since the completion of the first advanced well in 1997 the Company has now gained experience with more than two hundred remotely operated downhole valves and is further developing the potential of advanced completions. Some assets have been able to make more use than others of the potential offered by the technology. This paper presents a review of how advanced wells are being used, the added value generated through their use and the additional potential they can offer.
A Mathematical Model for Emulsion Mobilization and Its Effect on EOR During ASP Flooding
Authors: Lei Zhengdong , Yuan Shiyi , Song Jie , Yuan Jiangru , Wu Yu-Shu 
Published: April 2008

Abstract
Large-scale pilot tests of alkali-surfactant-polymer (ASP) flooding in the China's Daqing Oilfield reveal that emulsification occurs during ASP flooding and displacement. The flow of emulsions in porous media exhibits high viscosity, well-behaved chemical stability, and apparent non-Newtonian flow features. The genesis and mobilization of emulsions in reservoirs are an important part of ASP flooding processes, and entrainment and capture of such emulsions in porous media are considered to be important for improving oil recovery by ASP flooding. However, there are few studies that attempt a quantitative description of emulsion mobilization in porous media. As a result, the physicochemical phenomena of emulsions are not included in the current numerical simulation of ASP flooding processes.
Based on our experimental studies and field tests, we conducted an in-depth analysis of displacement mechanisms, emulsification, and flow behavior of emulsions in porous media during ASP flooding processes. In this paper, we describe the development of a mathematical model to describe such physicochemical emulsion phenomena. This mathematical model incorporates the mechanisms governing the interaction between emulsion droplets and pore structures, including emulsion genesis criteria, correlation of emulsion viscosity and water content, and permeability reduction caused by droplet capture. The model is implemented into an existing chemical reservoir simulator for numerical modeling studies of ASP flooding that considers emulsification mechanisms. Simulation results show that oil emulsification during ASP flooding has a significant impact on, and could improve, in situ oil displacement efficiency. The proposed model can be used for understanding the effects of emulsions in ASP flooding, within both laboratory studies and field applications.
Laboratory Evaluation of Water-Swellable Materials for Fracture Shutoff
Authors: Abbasy Imran , Vasquez Julio , Eoff Larry , Dalrymple Dwyann 
Published: April 2008

Abstract
The existence of high permeability features such as fissures, fractures, and eroded out permeability zones, diminishes the sweep efficiency of any water, gas, or polymer flooding. This paper presents the laboratory evaluation of three water-swellable materials (WSM) that can be bullheaded into the well to shut off fractures. The WSM, which swell on contact with water, would be mixed on-the-fly, entering fissures and fracture systems as they swell without invading the matrix of the rock. The rate of absorption can be controlled based on the particle size, carrier fluid, and formation fluid. This conformance technology is also applicable to address circulation-loss problems in production and injection wells.
The following materials were evaluated: (1) a polyacrylamide polymer, (2) a chloroprene rubber, and (3) a nitrile rubber. The polyacrylamide polymer is capable of absorbing 30 to 400 times its own weight in water while the two rubbers swell approximately 5 to 10 times their original weight. The WSM were evaluated for effectiveness to: (1) provide controllable swelling rates at different conditions, (2) shut off the flow of water in synthetic cores with simulated fractures at 135°F, and (3) provide long-term thermal stability in H2S and CO2 environments. In addition, the capability of the polyacrylamide polymer to withstand differential pressure was evaluated over time in a core-flow experiment.
Discussed are: (1) the methodology used for measurement of swelling properties for each material at different conditions including carrier fluid, particle size, and temperature, and (2) core-flow tests with simulated fractures. These materials are nontoxic and do not contain heavy-metal crosslinkers. Based on this study, these materials present an innovative technology for fracture shutoff and to help control circulation-loss problems. In addition, these materials are resistant to acid contamination in CO2 and H2S environments.
Application of a New Fully-Coupled Thermal Multiphase Wellbore Flow Model
Authors: Livescu S. , Durlofsky L. J. , Aziz K. , Ginestra J. C. 
Published: April 2008

Abstract
Thermal recovery processes are widely applied for the production of heavy oil and oil sands. Thermal reservoir simulation models, however, often lack a comprehensive well modeling capability. Such a capability is required to capture the detailed thermal effects that occur in the wellbore. These effects can be important as they impact wellbore pressure and temperature and thus production and injection. We recently developed a fully-coupled black-oil thermal multiphase wellbore flow model and implemented it into Stanford's General Purpose Research Simulator (GPRS). The model computes pressure, temperature, and oil, water and gas phase fractions along the wellbore as a function of time and includes treatments for slip between fluid phases, heat losses to the reservoir, and general variations of fluid properties with temperature and pressure. The purpose of this paper is to validate and test the coupled wellbore-reservoir model for challenging and realistic cases. The thermal wellbore model is first validated through comparison to field data for three-phase flow in a long well with both vertical and inclined sections. Close agreement between the model and field data is obtained. Complex wells containing multiple branches are then simulated, including a steam-water case with vaporization and condensation. The general conclusion from this work is that the new model is capable of simulating a wide variety of complex coupled reservoir-wellbore phenomena.
Performance Analysis of SAGD Wind-Down Process with CO2 Injection
Authors: Bagci A. S. , Olushola S. , Mackay E. 
Published: April 2008

AbstractThermal recovery methods involving steam injection have long been considered as an effective means of extracting heavy oil resources. In addition, the high recovery performance of SAGD makes it a popular option for these non-conventional oil resources. Steam processes are energy intensive and result in generation of emissions which are detrimental to humankind and the environment. The use of non-thermal processes involving CO2 as a miscible or immiscible gas phase in combination with steam for heavy oil recovery is considered as a viable alternative to limit the drawbacks of steam generation. These processes have the capability to enhance oil recovery through CO2 utilization during production and also provide an avenue to dispose CO2 after production. Numerical simulation studies have been carried out utilizing STARS (a three phase, multi-components reservoir simulator) to optimize a baseline SAGD process and wind-down process with CO2 Injection. The baseline process was operated until maturity then CO2 injection was used to initiate wind-down after 4, 6 and 8 years of a 12 year production operation. Following each of the wind-down processes, CO2 disposal was undertaken for 25 years and the storage potential evaluated. The baseline SAGD process had a recovery factor of 76%. The SAGD wind-down processes with CO2 injection after 4, 6 and 8 years had recovery factors of 54%, 77% and 79% respectively. This and other parameters proved the feasibility of SAGD wind-down process with CO2 injection and its potential to enhance oil recovery.