bluuebunny/crossref_metadata_2025_split huggingface dataset:
A Neural Network Approach for Real Time Evaluation of Sandstone Strength
Authors: Soroush H. , Tokhmechi B. 
Published: July 2010

Abstract
The integrity of the wellbore plays an important role in petroleum operations including drilling, completion and production. Oil and gas industry has been always suffering from wellbore stability and sand production problems which have been costly and time consuming to tackle. Having a good knowledge of formation strength and earth&apos;s stresses is the key for evaluation of well integrity during both drilling and production. Formation strength is usually obtained throught either experimental tests or interpretation of petrophysical logs. However, on one side, in most cases the core strength databases are limited, discontinuous and are often biased towards stronger intervals; on the other side, petrophysical logs can be adversely affected by drilling fluid, pore fluid and borehole shape and require to be calibrated against laboratory measurements. It raised the idea of approximating rock strength from some physical or petrographical properties of rock, which are more convenient to measure, even on drilling cuttings.
This paper aims to establish empirical relationships between sandstone petrographical features and the unconfined compressive strength (UCS). A comprehensive laboratory study was performed and reasonable correlations was established between the UCS values and a number of petrographical properties (including cementation degree, grain shape, median grain size, nature of graingrain contacts, average numbers of grains in contact, quartz content, clay content, sorting, and visual porosity).
Finally a multilayer perception neural network (MLPNN) model was designed to enable estimation of UCS using petrographical data. A workflow was presented for near real-time evaluation of formation by visual inspection and characterisation of drilling cuttings at rig-site with implication for controlling wellbore failure during drilling and production.
Using Optimization Techniques for Determining Optimal Locations of Additional Oil Wells in South Rumaila Oil Field
Authors: Al-Mudhafar Wathiq J. , Al-Jawad Mohammed S. , Al-Shamma Dunia A. 
Published: July 2010

Abstract
Determining the optimal location of the wells is a crucial decision to be made during a field development plan. A reservoir simulator called "SimBest II" has been used in the present study. The oil field under study is a sector of South Rumaila oil field/main pay. Two methods of optimization have been adopted in the present study. The first one is manual optimization and the second method is automatic optimization. Genetic Algorithm (GA) was used as the automatic optimization method to find the best number and locations of the wells. Genetic algorithm depends on the principle of artificial intelligence similar to Darwin's theory of Natural Selection. The genetic program is coupled with the simulator in order to re-evaluate the optimized wells at each iteration. The genetic algorithm computer program gave results similar to the results that are obtained by the manual method with less computer time. Both methods have been adopted according to the aspects of net present value (economic evaluation) as objective function. According to the relationship between net present value and future production time, the abandonment time was estimated before end of December 2014 for all proposed future scenarios. The optimal future scenario was with water injection of 15000 surface bbls/day per well. The optimal number of additional wells for this case was nineteen wells, but it may be impossible to drill such a number of wells in the one year especially in Iraq. Moreover, that an alternative option of drilling three wells with reduction of 0.07399 % in NPV has been considered. This option is also suggested if the surface injection facilities cannot handle the injection of 15000 surface bbls/day. The optimal number of additional wells for this choice is also three wells.
Surfactant Stimulation to Increase Reserves in Carbonate Reservoir: "A Case Study in Semoga Field"
Authors: Rilian Nova Arthur , Sumestry Meiliza , Wahyuningsih _ 
Published: July 2010

Abstract
Semoga field, which produces from Baturaja (carbonate) formation, has experienced a decline in production and has a high water cut (WC). The current average water cut in Kaji-Semoga field is 86%, while several producing wells have above 95% WC and even 100%. In 2007, Lemigas conducted a laboratory study to determine the wettability of Baturaja formation (BRF), the result of which was that BRF indicated very oil wet characteristics. However, after being immersed in surfactant, core samples became less oil wet. This test shows that trapped oil can be recovered using tertiary recovery methods. One option for confirming the laboratory test result is to use surfactant huff &amp; puff method in a pilot project.
Surfactant is a surface active agent compound which has the ability to reduce the surface tension between the rocks, produced water and crude oil so that wettability may change. The surfactant type to be used on BRF formation is non-ionic. The pilot huff and puff project was conducted on wells X-1 &amp; X-2. High WC wells with low WC at initial (early production) and high liquid production were selected to minimize risk and to yield more oil. This project was evaluated using pressure build-up test (transient analysis) and production performance monitoring before and after the surfactant stimulation job. An economic analysis was also conducted
As a result of employing surfactant stimulation, Semoga Field yielded NPV @ 3 month 24,013 USD with a pay-out time (POT) of 11 days. Oil gain would be more significant if the technique was implemented on high production wells.
Asphaltene Precipitation Study during Natural Depletion at Reservoir Conditions
Authors: Afshari S. , Kharrat R. , Ghazanfari M. H. 
Published: July 2010

Abstract
This study concerns with experimental investigations of asphaltene precipitation at reservoir conditions of a crude sample from an Iranian oil reservoir during pressure depletion. High pressure high temperature set up and filtration method was used to quantify amount of precipitated asphaltene at different pressures. In addition the effect of temperature on asphaltene precipitation during pressure depletion has also been examined. The experimental results have been used to develop the asphaltene precipitation model with the application of commercial software as well.
The movement of production systems to deepwater and subsea environments in recent years has increased the importance of fluid property related flow assurance issues. Fluid property variations that commonly occur during the production of oil, such as changes in pressure, temperature and composition, can precipitate asphaltenes. Asphaltene precipitation causes severe problems in reservoir oil production which is highly costly and laborious to remediate. Optimizing production in this case requires knowing the conditions under which asphaltenes will remain in solution. Experimental measurements at reservoir conditions play an important role in understanding asphaltene behavior as well as developing and justifying asphaltene models.
The results of this study confirm that asphaltene precipitation increases when temperature decreases, this can be interpreted as a result of variation in volume fraction of species when temperature changes. After the pressure onset, asphaltene precipitation increases with reduction of pressure and reaches to a maximum near the bubblepoint. Furthermore reduction in pressure leads to asphaltene redissolusion due to light gas liberation. Also it is revealed that denser asphaltene components have tendency to precipitate initially.
The results of this study can be applied as criteria for designing successful production operation in order to avoid asphaltene problem and also for thermodynamic model development or modification.
Real-Time Production Optimzation for a Mature Onshore Field in Austria
Authors: Nederlof E. F. , Huber S. 
Published: July 2010

Abstract
This paper will describe the results of a study to implement a Real-time Production Optimization initiative for a mature onshore field in Austria.
Oil and gas have been produced from Austria since the 40's. At this moment OMV Austria produces roughly 40.000 boe per day from approximately 810 oil and 100 gas wells. The wells are located in a large and complex geographical area. The oil wells are mainly produced by means of artificial lift. The artificial lift systems in place are sucker rod pumps, gaslift, ESP's and PCP's. Average production for these wells is around 20 bopd with a water-cut of roughly 95%.
In order to reduce OPEX, optimize workflows, increase production and further improve HSEQ performance the level of automation and control of the wells has to be increased. Additional sensors (Pressure, Temperature and Pump-Off controllers) have been defined for the different artificial lift methods. To achieve a greater operating flexibility all Beam pumps will be equipped with a Variable Speed Drive. Also flow control valves of the gaslift system need to be replaced. Besides the sensors it was identified that the power grid and communication need to be upgraded. In a number of cases the well sites have to be adjusted as well. The generated data will be analyzed on a software platform that allows Real-Time Production Optimization and provides warnings when wells are running outside the ideal operating envelope.
Costs for the defined scope of work have been gathered and evaluated and several implementation scenarios have been investigated. The dramatically changed economical situation as well as the large investment requirement for full field implementation did not proof to be economical. However a pilot project will be executed in 2010 to confirm the economical and technical assumptions.
Neural Networks in BHCP Prediction Performed Much Better Than Mechanistic Models
Authors: Ashena Rahman , Moghadasi J. , Ghalambor A. , Bataee M. , Ashena Rahim , Feghhi A. 
Published: July 2010

Abstract
Two phase flow applications in petroleum industry are so widespread. It is a fact that UBD precise bottomhole pressure maintenance ascertains UBD success. UBD hydraulics design, especially for inclined trajectories, is a real challenge. This is greatly dependent on the pressure drop in the annulus.
Two phase flow through annulus is an ambiguous area of study to evaluate the bottomhole pressure. Two phase flow correlations on which most of UBD simulators based on over predict and also make extrapolation risky. Although Mechanistic approaches increase the frequency for designing two phase flow systems in pipes, modeling them through annulus by using the hydraulic diameter concept is not so successful. For this reason, their corresponding errors are not small. Therefore, in this paper, Artificial Neural Network is made use of to evaluate BHP in the inclined annulus using two major Iranian Oil Fields. To compare BHP found by neural network, Naseri et al mechanistic model which is a popular mechanistic model for these two fields is applied.
ANN shows to perform much better than Naseri et al mechanistic model. The results show that neural network can estimate bottomhole pressure with an error of less than 20%. This proves that in case of existence of measured BHP while under balanced drilling, it is worth to use ANN to simulate BHP rather than mechanistic modeling or correlations.
ANN is highly shown to be useful for solving the non-straightforward problem of two phase flow in annulus. Few jobs have been done to prove the superiority of ANN to mechanistic modeling and correlations in terms of pressure prediction especially in under balanced drilling.
The Effect of Reservoir Wettability on the Production Characteristics of the VAPEX Process
Authors: Rezaei N. , Mohammadzadeh O. , Parsaei R. , Chatzis I. 
Published: July 2010

Abstract
Based on the pore-level visual investigation results of vapor extraction (VAPEX) process in etched glass micromodels, two major pore-scale recovery mechanisms were found responsible in the drainage of live oil, namely, 1) the drainage type displacement mechanism of gas invasion in a pore filled with oil and 2) the film flow drainage mechanism in the corners of pore space invaded by gas. Inspired by the role of film flow drainage in the recovery performance and production history of the VAPEX process, wettability was expected to play a profound role in the drainage of live oil by the stated mechanisms. Therefore, we examined the impact of fractional wettability on production characteristics of a VAPEX process at a macro scale. Conventional VAPEX experiments were conducted in a 220 Darcy random packing of glass beads in a rectangular physical model and used n-pentane to recover the Cold Lake bitumen from the oil saturated model. The composition of packed bed was changed from completely water-wet glass beads to completely oil-wet treated glass beads, at different compositions obtained by mixture design. It was found that the live oil production substantially increased (35-40%) from water-wet conditions to the extreme case of oil-wet conditions. A percolation threshold at about 65% oil-wet composition (35% water-wet) was found, after which the live oil production rate during VAPEX process did not change with further increase in the volume fraction of oil-wet beads. The production rate of VAPEX linearly decreased with increasing the volume fraction of water-wet beads over the 30% value in a random packing. It is believed that above the percolation composition, the oil-wet regions dominate the film flow process as there will be a continuity of high conductivity film through oil-wet regions, as a result of thicker (in size) bulk oil films between particles. The solvent content, the solvent-to-oil ratio (SOR), and the residual oil saturation did not correlate to the wetting composition of packing. The values obtained for solvent content were 47-49% (g/g), for the SOR 0.9-0.95 (g/g) and for the residual oil saturation 7-to-10 % of pore volume.
Optimal Reservoir Modeling Improves Development Decision Making for a Fractured UK Onshore Oil Field- A Case Study
Authors: Bozorgzadeh M. , Brown J. H. , Bobolecki R. , Meehan D. , Bone K. , Rawlinson A. 
Published: July 2010

Abstract
Optimal technical analysis and pre-development well planning has never been more important in establishing the commercial viability of smaller oil fields. This focus has been exacerbated by recent oil price variation, placing an increased onus on technical teams to make optimal development drilling decisions. This paper outlines a case study of successful technical work undertaken for the further development of the onshore Singleton field, Middle Jurassic carbonate reservoir, UK.
The field was discovered in 1989 and production from the field peaked in mid 1990's at c. 1,000 BOPD. Whilst reservoir porosity is fair to good, with some natural fractures evident, matrix permeabilities tend to be low, resulting in low recovery factors. The field had been producing c. 500 BOPD from 6 wells prior to the operator commencing a development study on the field. The aim of this study was to identify a development program that would significantly increase the reserves, recovery factor, and oil production of the Singleton field.
The Southern Block of the field was high-graded for the study due to its significant STOIIP. This block has been on production since 1990 with three producers online at the time of study. A simulation study was conducted for the area. Through well test analysis and sector modeling fracture and all other key unknown parameters were estimated. A full field model was built based on a 3D geological model and the derived parameters. These parameters were further adjusted to obtain good matching on production and pressure histories. Based on the simulation results, a production well was targeted to the west area of the block. It was predicted that this additional new well would increase the oil recovery factor by 2%. The effect of fracturing on the oil recovery factor was also investigated with a further increase in recovery factor of c. 2 to 3 % possible based on a range of low to high fracture densities.
A new development well was subsequently drilled based on the modeling results. This well came in on prognosis and encountered porous hydrocarbon bearing reservoir section with minor fracture development. The initial well performance has been close to that predicted by the simulation model, with rates and initial reservoir pressure matching the non-fractured simulation prediction case. The simulation modeling helped to improve the geological understanding of the fracture network present in the field. As the well results have demonstrated the viability of the modeling; a number of further development well locations are currently under review to continue the further development of the Singleton oilfield.
Development Planning for Multiple Fields Consisting of Stacked Sands and Containing Multiple Fluids, Jenein Sud, Tunisia
Authors: MANTATZIS Konstantinos , BOISSEAU Yannick , STECKHAN Jan , TORRES Pablo , CLEMENS Torsten 
Published: July 2010

Abstract
The Jenein Sud area is located in the south of Tunisia about 350 km from the Mediterranean Sea. Five successful wells have been drilled in the area and proved that structures containing various fluids are present and can be produced at economic rates.
In this paper, the main challenges encountered in the area and how they were tackled is described.
Pethrophysical parameters: Owing to diagenetic processes such as chloritisation, siderite cementation and quartz overgrowth, the porosity to permeability relationship is diffuse and cannot be consider for permeability estimation. Therefore, all available petrophysical datasets were integrated and clustered by using an appropriate rock typing concept, reflecting the influence of pore geometries on flow and storage.
Sand distribution: Sand layers could not be correlated laterally due to the prograding environment encountered and the large distance between the drilled wells. To capture the uncertainties, a multitude of geological models was created, integrating available seismic data, outcrop studies and trends apparent from regional geology.
Fluids: The individual structures consist of a large number of stacked sands. The fluids in the sands vary from dry gas to volatile oil. All the sands have individual hydrocarbon/water contacts. To determine the fluid composition of the layers and overall performance, MDT samples were taken from the sands and several production tests were performed. An overall Equation Of State model was used to describe the comingling of individual sand layers and to optimise the surface facility design.
Small scale structures: To appraise the area, wells have been drilled in individual structures rather than appraisal wells into selected structures. The wells are used to prove sufficient hydrocarbons and the composition of the hydrocarbons. This information was used to select an appropriate surface facility design capable of handling the fluids and to optimise the production strategy of the area.
EOR: Current Status and Opportunities
Authors: Manrique E. , Thomas C. , Ravikiran R. , Izadi M. , Lantz M. , Romero J. , Alvarado V. 
Published: July 2010

Abstract
A considerable portion of current world oil production comes from mature fields and the rate of replacement of the produced reserves by new discoveries has been declining steadily over the last few decades. To meet the growing need for economical energy throughout the world, the recoverable oil resources in known reservoirs that can be produced economically by applying advanced IOR and EOR technologies will play a key role in meeting the energy demand in years to come.
This paper presents a comprehensive review of EOR projects. Specifically, the paper presents an overview of EOR field projects by reservoir lithology (sandstone, carbonate, and turbidite formations) and offshore versus onshore fields. More than 1,500 field projects are reviewed and summarized to evaluate feasibility of EOR technologies. Another area of growing interest is the combination of near-well-bore and in-depth conformance technologies with chemical EOR technologies such as SP and ASP. However, these are in early stages of evaluation. Examples of numerical simulations combining chemical conformance and EOR technologies are presented showing the potential of this recovery strategy in waterflooded reservoirs. Impacts of carbon capture cost and volatility of oil and carbon-credit markets on CO2-EOR projects based on anthropogenic sources is also addressed.
Based on this review, it is evident that thermal and chemical EOR projects dominate in sandstone formations while gas and water-based recovery methods dominate carbonate, turbidite, and offshore fields. The review also shows the growing trend of CO2 (from natural sources), high-pressure air injection (HPAI), and chemical flooding including in-depth conformance field projects in the U.S. and abroad.
CO2-EOR / sequestration in offshore fields and chemical EOR processes offshore (e.g., polymer-based methods) and onshore, including heavy crude oil reservoirs, are some of the opportunities identified for the next decade based on preliminary evaluations and proposed or ongoing pilot projects. The critical review will help to identify the next challenges and opportunities in EOR. Hybrid schemes combining IOR/EOR as well as CO2-EOR/sequestration can be ranked on the basis of adequate simulation procedures.
Medium-High Permeability, Mature Reservoir Management Study: An Innovative Methodology and Case Study
Authors: Liu Xiantai , Wang Zhonghe Peter , Wang Yanzhong 
Published: July 2010

Abstract
Field-wide flow patterns for the 25-year waterflood production history of the medium-high permeability Gudong field, China have been carefully studied using a flow-based numerical simulation process. Through a history matching, field-wide streamline patterns and the cu1mulative flow between injector/producer well pairs can be displayed graphically and quantitatively via well allocation factors. By analyzing the flow pattern or streamline fields (field-wide and locally) for each time step through the reservoir production history, Predominant Streamline Fields (PSF) and Weak Streamline Fields (WSF) can be identified. The PSF can be classified into different levels based on statistically analyzing Strength Index of Streamline Field (SISF), which is a function of both allocation factor and the swept volume of the specific well pair at a given time step. Generally speaking, areas with strong PSF most likely indicate where reservoir channeling occurred at this specific time period, and this channeling is likely to persist until enough change is done. The relative stable WSF zones, with reasonable formation thickness have good potential to be bypassed pay.
To verify the findings above, a dozen conceptual models have been built and tested, and consistent results were found. This dynamic reservoir study processes provided an extra tool for reservoir scale waterflood optimization, well selection for profile modification/water shutoff, and infill drilling.
The Gudong case study indicated that PSF behavior began about 4~ 6 years from the start of water injection. That time period was consistent with a lot of other history data. The findings helped EOR and infill drilling in Gudong field.
Conclusions from this study have led to a better understanding of the displacement mechanisms and the nature-and-man-made dynamic-heterogeneity in the field, which may not be able to obtain otherwise.