bluuebunny/crossref_metadata_2025_split huggingface dataset:
Application of a Hybrid System of Genetic Algorithm & Fuzzy Logic as Optimization Techniques for Improving Oil Recovery in a Sandstone Reservoirs in Iraq
Authors: Al-Mudhafer Wathiq , Alabbas Maytham 
Published: April 2012

Abstract
An Interdisciplinary study for increasing oil recovery has been made in the present paper. This work has been adopted in the Upper Sandstone member/Zubair formation in South Rumaila Oil Field. The work was achieved by using optimization techniques for determining the optimal future reservoir performance regarding to infill drilling. Adaptive Genetic Algorithm (AGA) has been adopted in this paper to optimize the count and locations of infill wells. AGA uses Fuzzy Logic (FL) to determining optimal crossover rate, mutation rate and crossover form for each generation; in order to find accurate prediction. The main parameters depended in this study is the cumulative oil production obtained from the output of reservoir simulation software. This optimization tool depended on using the objective function of Net Present Value (NPV) as economic analysis. The optimal number of infill wells is three wells that have maximum cumulative oil production and maximum value of NPV. The locations of these optimal infill wells located in the crest of the oil field and far away from the east and west flanks because of the strong water drive from the infinite acting aquifer.
Pore Pressure Prediction in Carbonate Reservoirs
Authors: Atashbari V. , Tingay M. 
Published: April 2012

Abstract
Knowledge of pore fluid pressure is essential for safe drilling and efficient reservoir modelling. An accurate estimation of pore pressure allows for more efficient selection of casing points and a reliable mud weight design. Current commonly used methods of pore pressure prediction are based on the difference between a ‘normal trend’ in sonic wave velocity, formation resistivity factor (FRF), or d-exponent (a function of drilling parameters) and the observed value of these parameters in over-pressured zones. The majority of the techniques are based on shale behaviour, which typically exhibits a strong relationship between porosity and pore fluid pressure. However, carbonate rocks are stiffer and may contain over-pressures without any associated influence on porosity. Indeed, the application of common pore pressure prediction methods to carbonate rocks can yield large and potentially dangerous errors, even suggesting absences or decrease in abnormal pressure in zones of high magnitude over-pressure. In some cases, the hypothesises which been in the conventional methods seems to be flawed in some cases where pore pressure decreases by depth.
In this research, a new method for effective stress calculation has been obtained using the compressibility attribute of reservoir rocks. In the case of over-pressure generation by undercompaction (as occurs in most clastic over-pressured sequences), pore pressure is dependent on the changes in pore space, which is a function of rock and pore compressibility. In simple terms, pore space decreases while the formation under goes compaction, and this imposes pressure on the fluid which fills the pores. Carbonate reservoirs in two fields in Iran have been investigated to establish pore fluid pressure generation mechanisms, and to attempt new methods for pore pressure prediction in carbonate rocks.
Fiber Technology Simply and Effectively Cures Total Losses in Southern Mexico Without Knowing Size of Fractures
Authors: de Andrade Alexandre Victor , Diaz Lenin Omar , Bermudez Raul , Bedino Henry Daniel , Carrillo Nixklafe Neil , Vargas Candelario Delgado , Carrillo Angel Pedro , Martinez Ignacio Ramirez 
Published: April 2012

Abstract
Lost circulation is a major problem when drilling oil wells in Southern Mexico, where depths normally reach up to 7,000 meters with a fractured carbonate reservoir as the target. Very high mud losses reduces rate of penetration, increases cost of materials and induces other unwanted drilling events. Many times operators and service companies are forced to apply in-a-hurry lost circulation treatments mostly based on trial and error with very mediocre success.
A Fiber system has been developed to cure lost circulation caused by the presence of natural fractures. The fiber system is deployed either in a spacer ahead of cementing or by spotting a pill during drilling. This Fiber system disperses readily in water-base fluids and is fully compatible with standard surface mixing and pumping equipments.
This field study presents the application in Mexico of this innovative and resilient Fiber lost circulation system designed to mitigate the lack of characterization of the loss zone. Fourteen jobs performed and two applications described include pumping through commonly used BHAs during drilling, and as part of the spacer ahead of the cement slurry, when partial or total losses occurred with casing on bottom.
Implementation of this engineered fiber-based lost circulation solution was extremely successful compared to the average success of other similar purpose systems. Particularly, two features were considered a breakthrough in applications while drilling: first, this solution saved 15 to 24 hours of rig time per operation as the BHA needs not be pulled out; and a second, and perhaps more important advantage consisted in being able to resume drilling quickly after pumping the material without risking to destroy the integrity of the seal. When used in a spacer ahead of cement in wells, where circulation was lost after getting the casing to its landing depth, the Fiber lost circulation solution allowed to successfully getting top of cement at the planned desired depth ensuring effective zonal isolation.
Miscible Gas Injection and Asphaltene Flow Assurance Fluid Characterization: A Laboratory Case Study for a Black Oil Reservoir
Authors: Memon Afzal , Qassim Bashar , Al-Ajmi Moudi , Kumar Tharanivasan Asok , Gao Jinglin , Ratulowski John , Al-Otaibi Basel , Khan Rizwan Ahmed 
Published: April 2012

Abstract
Miscible gas flooding is the most commonly used enhanced oil recovery (EOR) method. One of the most important experimental parameters for miscible gas injection is minimum miscibility pressure (MMP). Many times, the MMP of a system can be very high. Instead of raising the pressure to achieve miscibility, injection gas may be enriched with intermediate components. The enrichment level at which the gas-oil system becomes miscible is called minimum miscibility enrichment (MME). Regardless of the values of MMP and MME, gas injected into a reservoir will most likely induce asphaltene precipitation, which may potentially cause formation damage and reduce flow in the production tubing.
In this paper, reservoir fluid from a Kuwait reservoir was analyzed to check for the feasibility of miscible gas injection. First, a series experiments were conducted to measure MMP with various gases using different techniques and MME testing with slimtube experiments. Moreover, the benefits, disadvantages, and applicability of each experimental method for EOR testing with gas injections were compared. Second, asphaltene precipitation upon gas injection was investigated in detail by measuring the precipitation onset conditions. Asphaltene precipitation onset was measured using a near infrared (NIR) light-scattering technique and a high-pressure microscope system to analyze the measured data. Finally, the asphaltene precipitation locus on a pressure-temperature (PT) diagram and the amount of precipitation were modeled for the reservoir fluid with different concentrations of injection gas. The modeling was carried out using a composition-based cubic equation-of-state approach. The experimental and modeling results indicated that an increase in concentration of injection gas appears to aggravate asphaltene precipitation.
Fracture Aging Evaluation in Tight Sands Using a Snubbing Unit
Authors: Irazuzta G. , Forni P. , Pons M. , Agüero Luis 
Published: April 2012

Abstract
One of the methods used to extend the production level and durability of low permeability gas wells is by conducting re-fractures. Although many case histories have been reported in the literature, limited information reporting the refracs long term performance is available. The reasons for this can be summarized as follows: –Any study conducted to test (Build Up) involves killing the well or at least controlling the production pressure. This condition generates changes in the production regime which generates certain uncertainties in the measurements precision.–The testing procedure may cause some type of formation damage that impedes recovering the original production regime.–Finally, if the well has a high production regime, long testing periods means losses in gas production.
This paper presents a study performed on a low permeability sandstone gas well located at the Neuquina basin, Argentina, were the performance of two fractured zones were evaluated by means of a Build up test conducted without killing the well. A snubbing unit was used to carry out several operations as removing the production installation, applying zonal isolation using plug and packer among other tasks.
Both zones under study had been stimulated three years before conducting the study using a CO2 foam fracture fluid. The operational sequence, stimulation treatments analysis and closure stress interpretation provided valuable information to understand the fractures aging response and to define and design re-fractures.
Improving Flow Assurance in Multi-Zone Fracturing Treatments in Hydrocarbon Reservoirs with High Strength Corrodible Tripping Balls
Authors: Carrejo N. , Welch J. , Solfronk M. , Johnson M. H. 
Published: April 2012

Abstract
Multi point hydraulic fracturing in unconventional hydrocarbon bearing shale reservoirs has been proven to greatly enhance production economics. A major component of these multi point fracturing systems consist of tripping balls used to actuate fracturing sleeves. The sleeves are used to focus fracturing initiation and placement. The tripping balls may experience pressures approaching 10,000psi. Recent technology has allowed as many as 40 individual fracture points. Once the formation has been fractured the tripping balls may hinder production. One potential problem is related to the tripping balls becoming stuck on the fracturing seats. Tripping balls remaining in the lateral can create a choking effect and also lead to problems if wellbore re-entry is required. These risks to production can lead to significant increased costs and potentially lost production. A new high strength corrodible material has been developed and used for tripping balls to alleviate these potential problems in these unconventional reservoirs. This material has yielded a truly intervention-less means of flow assurance. The mechanical properties and corrosion rates of these newly engineered materials have been investigated to determine the downhole performance. The characterization results of these materials will be discussed and compared to other materials currently used for tripping balls. The testing included investigation of the corrosion rates of these materials in brines and acids at various temperatures and pressures. Materials were also functionally tested on multiple ball seat configurations used in the multi-zone fracturing systems.
Quantification of Hydrocarbon Volume: An Example Using Rock Typing Methodology Applied in Cerro Negro Field, Eastern Venezuela Basin
Authors: Moya C. , Gunter G. W. , Mahadevan J. , Wolgemuth K. M. 
Published: April 2012

Abstract
For many years, geologists and engineers have used volumetric methods to quantify or estimate hydrocarbon volume contained in reservoirs. The economic producibility of the reservoirs, also depend on the flow characteristics. The overall level of uncertainty of the estimation depends on the uncertainty of the parameters that determine the oil volume such as porosity and the reservoir characteristics such as pay thickness. However, uncertainty of estimation increases when estimating hydrocarbon in place for complex fluids systems (i.e. heavy oil) since mobility can have an adverse effect on fluid movement. Determination of net pay cut-offs should be based on parameters that include flow and storage capacity.
Considering the requirement to establish a relationship between petrophysical cut-offs and rock types to estimate hydrocarbon in place, five different cases were used to quantify net pay parameters of the reservoir in the Cerro Negro field, Venezuela. The workflow that was applied: Identification of petrophysical rock types (PRT) from porosity and permeability data using core-based and log-derived petrophysical analysis,Definition of the relationship between PRT and faciesDetermination of pay cut-offs for reservoir and each PRT using conventional and contemporary methodologies,Comparison of the conventional and contemporary methodologies results,Estimation of pay cut-offs impact on the prediction of rock types and reservoir petrophysical properties in the estimation of volumetric.
This study demonstrates that the definition of PRT distribution is controlled by pore throat size instead of facies. From the six rock types defined in the field just three rock types (1, 2, and 3) are oil producing rock reservoir. The OOIP results vary significantly over a range of 500 MMstb, depending on which of the parameters are used as pay cut-offs.
In conclusion, estimating OOIP by applying petrophysical rock typing is an improved way to decrease uncertainty than OOIP estimation by reservoir unit. The results demonstrated that the choice of good pay cut-offs was the key to reduce the uncertainty in the estimation of the OOIP in the Cerro Negro field.
Supercritical CO2 Interaction with Montmorillonite Clay
Authors: AlOtaibi Fawaz M. , AlKhaldi Mohammed H. , Funk Jim J. , Shen Shouwen X. , AlQahtani Jassi F. 
Published: April 2012

Abstract
Clay swelling has been recognized as one of the main mechanisms of formation damage during various well operations. Many researchers have extensively investigated the effects of many parameters such as pH, and salinity of water-based fluids on montmorillonite swelling behavior. However, studies of supercritical carbon dioxide (CO2) interactions with montmorillonite clay have been limited. These interactions can affect injectivity during enhanced oil recovery (EOR) operations. Therefore, the main objective of this study is to investigate the swelling behavior of montmorillonite in supercritical CO2 as a function clay original state: dry or hydrated.
The swelling behavior of both Ca-montmorillonite and Na-montmorillonite clays in distilled water and supercritical CO2 was investigated at temperature values of 25°C. Nearly 1 g of each clay was soaked in 10 g of distilled water at the desired temperature and atmospheric pressure for 24 hours. Then, these swollen clays were soaked in supercritical CO2 for 24 hours at the desired temperature and at nearly 2,000 psi. Absorbed water content and increase in interlayer space, after each soaking stage, were determined using nuclear magnetic resonance (NMR) and X-ray diffraction (XDR).
Results based on this study have indicated that the swelling degree of Na-montmorillonite was higher than that of Ca-montmorillonite after being soaked in distilled water for 24 hours. After absorbing distilled water at 25°C, the (001) d-spacing of dry Ca-montmorillonite of 14.95 Å increased by 25%, while the (001) d-spacing of dry Na-montmorillonite of 11.67 Å increased by 60.4%. The (001) d-spacing of these swelled clays decreased after they were soaked in supercritical CO2. For example, the (001) d-spacing of hydrated Na-montmorillonite of 18.72 Å decreased by nearly 25% after soaking in supercritical CO2for 24 hours at 25°C and 2,000 psi. This paper presents new interesting interaction results of shrinkage, swelling behavior and structure change of montmorillonite clay after interaction with supercritical CO2, which are important for different EOR operations.
Water Conservation: Reducing Freshwater Consumption by Using Produced Water for Base Fluid in Hydraulic Fracturing–Case Histories in Argentina
Authors: Bonapace J. , Giglio M. , Moggia J. , Krenz A. 
Published: April 2012

Abstract
In the Golfo San Jorge basin (GSJB), in the area of Cerro Dragón, a sustained increase of activity has developed over the past ten years. Further development of the field has been achieved with well stimulations (hydraulic-fracturing treatments), increasing production rates.
This has resulted in increased water consumption for these operations. In an effort to ration water sources, well owners must find alternatives to reduce the volume of fresh water consumed.
Throughout the past five years, one operator has worked to use produced water, or low-quality injection water, as a source of water for stimulation applications. The methodology applied consisted of Identifying different types of water produced in the fieldPerforming tests on the waters (physical-chemical and bacteriological)Performing tests with commonly used fracturing fluids to identify good performanceConducting tests during field operationsEstablishing procedures for water injection from the results obtainedContinuous monitoring, as well as the introduction of new techniques and improvements
The results that were obtained demonstrate how the operations performed have gradually increased by using this methodology (412 of 760 fracturing treatments during 2010). In addition, the reduction in freshwater use was 54.8% of the total amount in 2010 (5.7 of 10.5 million gal).
This work has helped identify sources of produced water in the field that are acceptable for use in fracturing stimulation operations. A procedure has been established to help ensure a reliable fracturing fluid with good performance is always used in these operations. Additionally, new techniques and equipment have been incorporated that contribute to continuous improvements to the process.
Studies On Nitrogen Foam Flooding For Conglomerate Reservoir
Authors: Hou Qingfeng , Zhu Youyi , Luo Yousong , Weng Rui , Guoqing Jian 
Published: April 2012

Abstract
Keshang formation in Karamay oil field belongs to typical conglomerate reservoirs. It is characterized by high water cut, poor sweep efficiency, high heterogeneity and inefficient oil recovery during the end-period of water flooding. The selection of EOR technique is very important for future development of such reservoirs. Foam flooding can improve macroscopic sweep efficiency, which may increase oil recovery for highly heterogeneous reservoirs particularly. In this study, systematic laboratory studies on foam flooding for Keshang formation have been performed.
Both the foamability and stability are the key factors to ensure high incremental oil recovery. The nitrogen foam formulas were optimized which had good performance of foamability and stability. The operating parameters including foam injection modes and gas liquid ratio were investigated by core flooding experiments at reservoir conditions.
The results show that: 1. Injection mode is an important factor and the direct injection of foam is better than co-injection of gas and solution obviously. 2. The gas liquid ratio is another important parameter. The optimized gas liquid ratio was proposed as 3:1-5:1 for direct injection mode. EOR effect evaluation indicated that foam flooding could contribute 40.00% OOIP recovery even if the recovery after water flooding was 41.50% under good operating protocols. The remarkable increasing of injection pressure during the foam flooding indicated that nitrogen foam flooding had excellent profile control ability.
Foam flooding integrates both properties of gas injection technique and chemical flooding. It is a candidate EOR method for highly heterogeneous conglomerate reservoirs.
A Framework for Consolidating Air Injection Experimental Data
Authors: Rodriguez E. , Ordoñez A. , Comas J. , Trujillo M. , Belgrave J. D. 
Published: April 2012

Abstract
Accelerating-Rate Calorimeter (ARC), Ramped-Temperature-Oxidation (RTO), and Combustion Tube (CT) tests are used for screening and designing air injection processes for enhanced oil recovery. These tests use different size samples of reservoir materials, operating under different conditions, have different interpretation requirements, and yield different types of information.
ARC data have been used to provide rapid screening of the suitability of (especially) high pressure light oil reservoirs for air injection. Small reservoir samples are used, air injection displacement efficiency is not captured, but they provide explicit quantitative oxidation rate information. RTO experiments use larger quantities of core and reservoir fluids and allow some fluid displacement and production. Due to the nature of this type of test, a much larger fraction of the oil is consumed compared to field application, and oxidation data over a broad range of temperatures is implicitly provided. Finally, combustion tube tests provide the closest dynamic analog to actual reservoir conditions and have the largest core and fluid requirement.
This paper describes a systematic procedure used to consolidate the data from these tests into a robust kinetic model for the design and implementation of air injection processes in heavy oil mature fields. The model considers both low and high temperature oxidation reactions, thermal cracking, and the compositional changes that the oil undergoes. Application of the model at the field scale shows temperature levels, produced gas compositions, and fuel and air requirements comparable with those derived from the combustion tube tests.