bluuebunny/crossref_metadata_2025_split huggingface dataset:
Integrated Clustering/Geostatistical/Evolutionary Strategies Approach for 3D Reservoir Characterization and Assisted History-Matching in a Complex Carbonate Reservoir, SACROC Unit, Permian Basin
Authors: Gonzalez R. , Schepers K. , Reeves S. R. , Eslinger E. , Back T. 
Published: April 2008

Abstract
An integrated methodology combining clustering analysis techniques, geostatistical methods and evolutionary strategy technologies was developed and applied to an area in the SACROC Unit (Permian basin). Clustering methods were applied to well logs and core data with high vertical resolution for many wells to predict porosity, permeability and rock type. Geostatistics was applied to extend the characterization into the inter-well area. Evolutionary strategies were used to refine the characterization to match historical production performance.
The complete approach was tested on an area within the SACROC Unit, acknowledged as a highly heterogeneous carbonate reservoir with complex production history. Three cored wells provided porosity and permeability measurements on a foot-by-foot basis. These measurements coupled with well logs were used to predict porosity, permeability and flow units. Twenty two wells in the study area having foot-by-foot profiles of porosity and permeability were considered sufficient to characterize porosity and permeability in three dimensions. Geostatistical methods were then used to build porosity and permeability models.
As a validation of the characterization procedure, evolutionary strategy jointly coupled with a black oil reservoir model was used to history match production performance of a 0.5 mi2 area. The 65,340 grid-block model had over 50 years of production. Thirteen (13) input parameters were varied during the history match. Among them, a multiplying factor was applied to the permeability realization to account for upscaling effects, varying permeability values without modifying geological heterogeneities identified during the characterization process. No adjustment to porosity characterization was permitted.
A very good history match of individual production was achieved for the center wells of the area, and a good match was also obtained for outer wells production and reservoir pressure where boundary effects existed. This validates the new integrated clustering/geostatistical/evolutionary-strategy approach in this highly heterogeneous carbonate reservoir.
Effect of Heterogeneous Capillary Pressure on Buoyancy-Driven CO2 Migration
Authors: Saadatpoor Ehsan , Bryant Steven L. , Sepehrnoori Kamy 
Published: April 2008

Abstract
We examine buoyancy-driven multiphase flow when the less dense phase is placed below the other phase in a heterogeneous domain. After generating geostatistical realizations of permeability, we apply the Leverett.J-function so that each grid block has a drainage curve (Pc vs Sw) physically consistent with its permeability. The behavior of the displacement front depends strongly on the correlation structure of the heterogeneity and upon the magnitude of the mean entry pressure. This behavior is of particular interest for assessing the degree of immobilization of anthropogenic CO2 injected into an aquifer.
In a relatively homogeneous domain, capillarity is a second-order effect. It damps the instability of the rising CO2 front and smooths the shape of the plume. As the heterogeneity of the aquifer increases, capillarity begins to dominate buoyancy. Regions with smaller permeability that would readily conduct single-phase flow can completely block rising CO2, simply because the capillary entry pressure in these regions is somewhat larger than in neighboring regions. These local capillary barriers prevent CO2 from rising and cause it to move laterally. The disruption can be so extreme that above-residual saturations of CO2 become trapped below these barriers. These local accumulations respond differently when the top seal of the aquifer is breached. Thus we distinguish them as a new mode of CO2 trapping, dubbed "capillary trapping." Overall, in some regions the CO2 follows preferential flow paths determined by the spatial correlation of permeability, while in others capillarity determines the flow path. Though the displacement front is much less uniform, the extent of dissolution trapping remains significant.
Evaluation of Manson Lease Oil Field for Improved Oil Recovery Process
Authors: Tsau J. S. , Vaca Bustamante V. , Green D. W. , Barnett B. , Dale J. L. 
Published: April 2008

Abstract
Typical oil fields in eastern Kansas area are shallow, low temperature reservoirs. Historically, waterflooding has commonly been applied as a secondary oil recovery method. In some cases, polymer flooding has been used to optimize the recovery of waterflooding. A polymer augmented waterflood was applied at the Manson lease, part of the West Savonburg oil field, starting in 2000. The lease had a very poor oil recovery and a study was initiated to evaluate reservoir performance in an attempt to understand the cause of the poor recovery. The evaluation processes included development of a geological model, core analysis and reservoir simulation. Poor sweep efficiency was found to result from water channeling thought to be caused by fracturing wells unintentionally during the polymer injection. As a result of the study, infill drilling and modification of field injection were implemented to continue the waterflood. In addition, the feasibility of CO2 application in this low temperature, low pressure reservoir was explored. Oil swelling factors and minimum miscibility pressure were measured using a vapor-liquid equilibrium view cell and a slim-tube apparatus, respectively. At the current reservoir conditions, the displacement of CO2 was found to be an immiscible process and, in general, not an economically viable process.
Investigation into the Processes Responsible for Heavy Oil Recovery by Alkali-Surfactant Flooding
Authors: Bryan J. , Mai A. , Kantzas A. 
Published: April 2008

AbstractThis paper describes a suite of alkali-surfactant (AS) floods that were performed in systems containing viscous heavy oil (11,500 mPas). The study investigates how AS injection can be used to generate oil and water emulsions, which can in turn lead to improved sweep efficiencies and oil recovery. Data is obtained from core flooding, with in-situ saturation measurements made using low field NMR. This work is applicable to the many heavy oil reservoirs in countries like Canada and Venezuela that contain viscous oil that still has some limited mobility under reservoir conditions. In previous studies, improved oil recovery compared to waterflooding was observed. This work provides additional information that can be used to better understand how chemical injection can lead to oil recovery.The core floods in this study indicate that emulsification is most efficient when used to block pre-formed water channels and improve the sweep efficiency of the flood. Both O/W and W/O emulsions may form in the same system, even under controlled salinity conditions. The re-distribution of water from the flooded channels into emulsified droplets in the oil is at least partially responsible for the pressure increase seen in these systems. W/O emulsification is accompanied by wettability alteration, as evidenced by the NMR spectra obtained. After the chemical flood is completed, it may be possible to restore the original water wet condition of the rock, which can provide potential for future non-thermal improved oil recovery.
Investigation of Diffusion Coefficients of Heavy Oil and Hydrocarbon Solvent Systems in Porous Media
Authors: Luo H. , Kantzas A. 
Published: April 2008

Abstract
Solvents can be injected to dilute viscous heavy oil or bitumen and improve the recovery of the vast reserves of heavy oil and bitumen in Canada. In an evolution of the SAGD and VAPEX processes, some new schemes that use solvent and steam appeared to offer a more economical and environmentally sound alternative to extract heavy oil and bitumen compared to SAGD alone. Mass transfer rates determine whether these solvent-assisted processes are feasible for heavy oil and bitumen recovery. The solvent-bitumen diffusion coefficient is a basic parameter needed. According to previous literature, the effective diffusion coefficient in porous media is much smaller than the true diffusion coefficient in bulk fluids. However, good-quality data from diffusion experiments of heavy oil and hydrocarbon solvent systems for effective diffusion coefficients determination in porous media is still scarce. This paper presents diffusion experiments of liquid solvent in heavy oil saturated sand using X-ray Computer Assisted Tomography (CAT), and determines the effective diffusion coefficients based on an updated approach, which considers porosity variation of porous media and volume changes on mixing. In addition, the relationship between the effective diffusion coefficient of solvent in oil saturated sand pack and the true diffusion coefficient in bulk fluids is investigated.
Case Study on Preformed Particle Gel for In-Depth Fluid Diversion
Authors: Bai Baojun , Huang Fusheng , Liu Yuzhang , Seright R. S. , Wang Yefei 
Published: April 2008

Abstract
The paper describes preformed particle gel (PPG) treatments for in-depth fluid diversion in four injection wells located in the north of Lamadian, Daqing oilfield, China. Lamadian is sandstone oilfield with thick net zones. The selected four injectors have 46 connected producers with average water cut of 95.4% before treatment. The paper reports the detailed information for the four well treatments, including well candidate selection criteria, PPG treatment optimization, real-time monitoring result during PPG injection and reservoir performance after treatment. In addition, a discussion is made to analyze why so large amount of large particles can be injected into the reservoir. Large volume of PPG suspension with concentrations of 2,000–2,500 mg/L and particle sizes of 0.06–3.0 mm was injected into each well and it took about 4 months to finish each injection. The injection volume ranges from 11,458 to 17,625 m3 per well with a total of 56,269 m3 of PPG suspension (295,680 lbs of dried PPG) for the four wells. During PPG injection, the increase of the wellhead pressure was quite stable and no PPG was produced from adjacent producers. Recorded real-time monitoring Data about injection pressure and rate, PPG particle size change during PPG injection provide invaluable information to analysis the possibility of fracture/channel in the reservoir. The treatments resulted in an oil increase of 34.8 t/d and average water cut decrease of 0.94% within 10 months after treatments.
A Successful Gas Injection Pilot Test in a Mature and Complex Fractured Carbonate Reservoir, Oxiacaque Field, Southern Mexico
Authors: Arteaga M. , Molina J. , Hernández R. , Flamenco F. 
Published: April 2008

Abstract
This paper presents the main results of a sour gas injection pilot test performed in the Oxiacaque field, a mature and natural fractured carbonate reservoir in southern Mexico. This field is part of a complex called the Complejo Bermúdez. The Complejo is the largest oil accumulation in terms of production in the Mexican Southern Region. It was discovered in 1973, and it consists of five producing fields referred to as Samaria, Íride, Cunduacán, Platanal and Oxiacaque. The oil gravity in Oxiacaque field ranges from 29 to 31 °API and it is producing from highly fractured carbonates of Cretaceous and Jurassic ages.
Oxiacaque field is located to the east of Cunduacán and North of Íride field. As of August 31, 2007, Oxiacaque has produced 161 MMBBL of oil and 426 BCF of gas. It produced 11 MBBL of oil and 52 MMCF of gas per day, from 7 active wells during August 2007. Structurally Oxiacaque is the highest field in the Complejo Bermúdez and has had some wells shut in due to high GOR production. At the initial formation pressure of 7610 psia at 15,223 ftss and a temperature of 277°F, the oil is undersaturated with a saturation pressure of 4565 psia. After 34 years of production, a secondary gas cap has been formed. Current reservoir pressure is 2275 psia.
Prior to implementing a full field injection project, a pilot test with sour gas was performed in this field. Major objectives of this pilot were: (a) to evaluate the efficiency of immiscible gas injection in maintaining reservoir pressure, (b) to evaluate its benefit on oil production, (c) to confirm level of pressure communication in the other fields – a critical issue for expanding the project – and (d) apply a coordinated plan of gas injection monitoring and surveillance from subsurface to surface, as an aggregated value to develop field experience. All of these objectives had a strong dependency on the complexity of the fracture system, the influence of faulted blocks and the critical rate of injection. It is believed that the injection rate seriously affected a previous water injection project, with channeling and fast breakthroughs in Samaria and Cunduacán fields.
The sour gas injection pilot was initiated in the Oxiacaque field in November 2006. At the end of August 2007, a volume of 13 BCF of gas has been successfully injected through two lower and upper Cretaceous wells, at an average rate of 30 MMCFD per well.
Possible Mechanisms and Case Studies for Enhancement of Oil Recovery and Production Using In-Situ Seismic Stimulation
Authors: Kostrov Sergey , Wooden William 
Published: April 2008

Abstract
Beginning in the early 1980's and continuing for several decades, interest in elastic wave stimulation focused primarily on acoustic and to a lesser degree on surface vibroseis1,2,3,4. In the late 1990′s a third type of elastic wave stimulation, in-situ seismic stimulation was developed by Applied Seismic Research Corporation5,6,7 (ASR). The ASR Hydro-Imapct tool creates high-energy elastic waves identical to earthquakes but at reservoir datum (in-situ) and lower magnitudes. Theoretical and experimental research performed by many independent laboratories has supported these claims.
Extensive field studies using seismic stimulation have proven to increase oil production and oil recovery (EOR) an average of 20–40 percent in wells at distances as far as 1 mile from the tool. Some wells have shown truly remarkable increases exceeding 500 percent. In September of 2007 the Texas Railroad Commission certified seismic stimulation as the first new EOR process in several decades. EOR certification gives Texas operators using seismic stimulation a 50 percent reduction in severance tax on total production for 10 years.
This paper presents a theoretical background and stimulation results on all types of oil fields
CO2 Storage in Low Permeability Formations
Authors: Cinar Y. , Bukhteeva O. , Neal P. R. , Allinson W. G. , Paterson L. 
Published: April 2008

Abstract
This paper investigates ways in which CO2 storage in low-permeability formations might be made viable and how such formations might compete with more distant formations with higher permeability. Hypothetical, but realistic cases are postulated to examine the effect of reservoir engineering and economic sensitivities. The cases compare (a) a large CO2 source with nearby abundant low-permeability pore space (0.1–10md) with (b) the same source with storage in a remote high permeability (100md) site. Based on reservoir engineering and economic analyses, the paper quantifies the injectivity of the sites, assesses the number of wells required and finally estimates the costs of capturing CO2, transporting it to the storage sites and injecting it into the sub-surface.
The paper shows that for the given assumptions, Carbon Capture and Storage (CCS) in the remote high-permeability formation can be significantly cheaper than CCS in the low-permeability storage site. The cost advantage of the considerably higher permeabilities expected in the remote area by far outweighs the cost of transport over the extra distance. This is the case despite applying horizontal drilling and fracturing technologies.
The economics of both the low and high permeability formations can be improved markedly by using horizontal rather than vertical wells. However, CCS in the remote high-permeability storage site still retains its cost advantage using this technology. Fracturing increases injectivity considerably for low permeability reservoirs and for both vertical and horizontal wells. However, it does not have a significant effect on reservoirs that have high permeability. Therefore, the technology helps injection in the low-permeability storage site much more than in the remote high-permeability storage formations. However, although under some conditions the relative economics of the low-permeability formation can be improved significantly by fracturing the low-permeability formation, the improvement is not sufficient to reverse the cost disadvantage of the low-permeability storage site.
Flood Front Tracking and Pulse Test Time Lags
Authors: Orangi Abdollah , Ershaghi Iraj 
Published: April 2008

Abstract
Improvements in downhole sensors have opened up new opportunities to obtain continuous recordings of rate and pressure data at producing and injection wells. We have examined the progression of lag time at observation wells when injection wells are subjected to pre-scheduled or unsupervised rate changes. A monitoring of time lags and comparisons with that corresponding to the first pulse at the start of injection is correlated with the location of displacement front. Analytical solutions to calibrate numerical test cases for linear and radial flow geometries are presented. The results of these systems demonstrate the potential of monitoring repeated pulses for front tracking in immiscible fluid displacement processes.
Mechanism of the Effect of Micro-Forces on Residual Oil in Chemical Flooding
Authors: Xia H. F. , Wang D. M. , Wang G. , Ma W. G. , Liu J. 
Published: April 2008

Abstract
Experimental results indicate that the displacement efficiency (De) after flooding by driving fluids with and without elastic characteristics is different at the same viscosity, (i.e. at the same pressure gradient). Macro forces cannot explain the difference of the De by different driving fluids. Therefore, the changes of micro forces acting on residual oil by driving fluids with elastic properties and the increase in the De are analyzed.
In this paper, through theoretical and experimental analysis, the influence of elastic characteristics of the driving fluid on De is analyzed. The changes in the streamlines and velocity of different fluids flowing in simplified pore models are mathematically simulated, the changes in micro forces caused by the change in velocity and streamline and its effect on residual oil are analyzed. This micro force does not change the pressure gradient and mainly acts on the protruding portion of different types of residual oil, causing the protruding portion to change shape and mobilize or migrate. The results on visualization core models confirm the above calculation and analysis, the De after flooding by fluids with different elastic properties are given.
The above research results show that the streamlines and velocities in pores are different when the elasticity of the displacing fluid varies, micro forces acting on the residual oil protruding portion increase with the increase in elasticity, resulting in an increase in De for visco-elastic displacing fluids at constant pressure gradient conditions.
This method of micro force analysis and its conclusions should be useful to further understand the mechanism of displacement efficiency in porous media, should be useful in designing, screening and developing better chemical flooding products, should be useful in the further development of the mechanism of micro seepage flow through porous media.
New Developments in Production Technology for Polymer Flooding
Authors: Yan Wang , Demin Wang , Jun Wan , Jiangtao Luo , Runtao Yu , Zengyou Dong 
Published: April 2008

Abstract
After large scale polymer flooding in the field, due to the high elasticity and viscosity of the fluid, the efficiency and effective life-span of the producers (and injectors) decreased significantly, new technologies were developed.
After polymer is produced, severe eccentric wear on sucker rods occur. To solve the problem, on the basis of theoretical and lab studies, techniques to reduce the normal force on sucker rods and control its eccentric wear were developed. Field practice shows that this technology has increased the average life span of pumping wells by 3 times.
The effective time of conventional fracturing and acid stimulation of polymer injectors is less than 3 months. Therefore, technologies of resin-coated sand tail-in fracturing and surfactant stimulation were developed. These 2 new technologies have increased the effective time of injector stimulation by about 5 times.
The above techniques are all used in a mass scale in the field with significant results; they can and are also used on conventional wells.
Review of Practical Experience & Management by Polymer Flooding at Daqing
Authors: Dong H. Z. , Fang S. F. , Wang D. M. , Wang J. Y. , Liu Z. , Hong W. H. 
Published: April 2008

Abstract
This paper describes successful experiences employed during polymer flooding at Daqing that will be of considerable value to future chemical floods, both in China and elsewhere. Based on laboratory findings, new thoughts have been developed that expand conventional ideas concerning favorable conditions for mobility improvement by polymer flooding. Particular advances integrate reservoir engineering approaches and technology which is elementary for successful application of polymer flooding. These include: (1) Considering permeability differential among the oil zones and interwell continuity, optimizing the oil strata combination and well pattern design. (2) The injection procedures and injection formula are the key points when designing a polymer flood project. These points include: profile modification is needed before polymer injection and zone isolation is of value during polymer injection, higher molecular weight of the polymer used in the injected slugs, large polymer bank size, higher polymer concentrations and injection rate based on the well spacing and injection pressure. (3) Characterizing the entire polymer flooding process in five stages, with its dynamic behavior distinguished by the water cut changes. Additional techniques involved with reservoir engineering should also be considered, such as dynamic monitoring using well logging, well testing, and tracers. Effective techniques are also needed for surface mixing, injection facilities, oil production, and produced water treatment.
Continuous innovation and effective response to new challenges must be a priority during polymer flooding. New directions and opportunities at Daqing will (1) explore the feasibility of polymer flood application in poorer ("third-class") strata, (2) to identify new polymers to suit portions of the reservoir with higher temperatures and higher water salinities, and (3) continually see improvements in our approach to polymer flooding.