bluuebunny/crossref_metadata_2025_split huggingface dataset:
Facies Based Approach to Amin Reservoir Characterization In A Heavy Oil Field In The South Of Oman
Authors: Lukmanov Rinat 
Published: December 2012

Abstract
The field X is a brown heavy oil field producing under strong bottom water drive since the mid-1980. Production is from a combination of Amin aeolian and Al Khlata glacial reservoir sediments. At present, the development is focused on drilling horizontal infill wells. One of the biggest challenges is the unfavorable mobility contrast between the heavy oil and water causing early water breakthrough.
The Amin Formation, the primary reservoir, is characterized by a high net to gross ratio and an average porosity of 30 %. However the initial hydrocarbon saturation at the same porosity often varies by 20 % in different parts of the field. Furthermore, core measurements show an order of magnitude scatter in permeability at the same porosity, indicating the presence of different facies. In early studies these variations were attributed mainly to the grain size variations. A later petrographical study found that the abundance of clays and feldspars could also severely reduce permeability, but may retain high porosity.
In the current Study it was found that the rocks have variable radioactivity due to the presence of radioactive Potassium isotope associated with feldspars. A fare correlation was observed between the grain size and the content of feldspars from core. A novel approach to reservoir characterization integrating core and logs was developed leading to a major breakthrough in the reservoir characterization including: Enhanced permeability prediction using normalized Gamma Ray (GR) log as 3rd parameter;Facies identification using normalized Gamma Ray cut-off;Facies based Saturation-Height models.
This work is a good example of advances in reservoir characterization achieved by integrating core and log data. It results in better understanding of reservoir properties distribution, optimization of completions of new wells and improvement of further development scenarios. In particular, abnormally high gross production and high water cut in the north of the field is currently in line with new facies scheme.
Intelligent Completion Technology Enables Selective Injection for Pressure Maintenance in Mature Field in South China
Authors: Wee Keith Heng , Finley Douglas B. 
Published: December 2012

Abstract
Pressure maintenance support in mature fields where permeability heterogeneity is present requires proper distribution of injected water into the respective zones of interest. This process can be extremely challenging, if no method for allocating the proper amount of water into each zone is available. An operator in the South China Sea, who had initiated a water injection project using legacy single-string two-zone completion technologies, found himself in this predicament, since no selective control for pressure maintenance had been considered for the project.
During the past few years, the application of intelligent completion (IC) technology has increased rapidly. This acceptance has been due primarily to its proven capabilities for reservoir monitoring and corresponding optimization of well performance without well interventions. Historically, the majority of IC applications have been in production wells; however, an increasing number of operators have started adopting IC technology for their injector wells.
This paper presents a case study in which IC technology was successfully applied in an offshore field in the South China Sea to provide an efficient water-injection method for optimizing pressure support as well as sweep. The operator selected this technology, as it presented a solution for optimizing the water injection. In addition to eliminating problems experienced with the incapability of the legacy completion technology to monitor water allocation and pressure maintenance for each zone, the IC technology would allow selective well testing for each zone. By evaluating the reservoir properties and characteristics of each zone independently, an intelligent completion would provide another key benefit to the operator, since it would comply with the platform size restrictions for the pumping equipment.
The paper will discuss field objectives, the conceptual design, the design obstacles, and the operational challenges experienced during the job execution.
Increasing Oil Recovery with CO2 Miscible Injection: Thani Reservoir, Abu-Dhabi Giant Off-Shore Oil Field Case Study
Authors: Aljarwan Abdulla , Belhaj Hadi , Haroun Mohamed , Ghedan Shawket G. 
Published: December 2012

AbstractThis paper aims to study the miscibility features of CO2 miscible injection to enhanced oil recovery from Thani-III reservoir. A Comprehensive simulation model was used to determine multi contact miscibility and suitable equation of state with CO2 as a separate pseudo component using one of the industry’s standard simulation software. Experimental PVT data for bottom hole and separator samples including compositional analysis, differential liberation test, separator tests, constant composition expansion, viscosity measurements and swelling tests for pure CO2 were used to generate and validate the model. In addition to that, simulation studies were conducted to produce coreflooding and slimtube experimental models, which were compared with the conclusions drawn from experimental results. Results of this study have shown comparable results with the lab experimental data in regards to minimum miscibility pressure (MMP) calculation and recovery factor estimation, where the marginal errors between both data sets were no more than 7% at its worst. Results from this study are expected to assist the operator of this field to plan and implement a very attractive enhanced oil recovery program, giving that other factors are well accounted for such as asphaltene deposition, reservoir pressure maintenance, oil saturation, CO2 sequestering and choosing the most appropriate time to maximize the net positive value (NPV) and expected project gain.
An Iterative Solution to Compute Critical Velocity and Rate Required to Unload Condensate-Rich Saudi Arabian Gas Fields and Maintain Field Potential and Optimal Production
Authors: Al-Jamaan Hamza , Zillur Rahim , Bandar Al-Malki , Adnan Al-Kanan 
Published: December 2012

AbstractSaudi Arabian non associate gas reservoirs produce various amounts of condensate depending upon field and reservoir. In most cases, these wells are hydraulically fractured and at the initial stage after such stimulation treatment, each well needs to unload high quantity of the pumped fluid to ensure full potential. If the liquid starts accumulating in the wellbore during production, the well productivity will gradually decrease and eventually may stop producing. If the gas flow velocity in the production string is high enough, the gas will continue flowing and will carry the liquid droplets up the wellbore to the surface. The minimum velocity and critical gas rate (Qcrit) are therefore the determining factors while producing a well or several wells from a condensate-rich field so as to ensure the stable field production rate and maintain production plateau.An analytical model has been developed to iteratively compute the critical velocity (Vcrit) and Qcrit, for given flowing wellhead pressure (FWHP), tubing diameter, and many other reservoir and completion properties. If the FWHP is set and a certain production rate is expected of a well, the program automatically computes the pressure drop due to friction, dynamic hydrostatic head, and the bottomhole pressure. Simultaneously, both Vcrit and Qcrit to unload the fluids are calculated. If the Qcrit is above the expected production rate, a different wellbore completion is automatically selected and computation is continued until Qcrit is lower than the expected rate of the well. If this is not possible, the program will display appropriate message.Several wells from a condensate gas reservoir are analyzed from a field that has to maintain certain production potential for a given number of years. The analyses show that the wells that are producing without intervention are those that are confirmed by this model to be flowing above the Qcrit. For wells that were intermittently producing and ultimately could not sustain production were producing at rates below the critical values. Using this iterative model, those rates are automatically adjusted or new completion string is suggested to bring them back into production.
Estimating Flow Rates Based on ESP Down Hole Sensor Data
Authors: Caicedo Sergio , Montoya Cesar 
Published: December 2012

Abstract
At Kuwait Oil Company (KOC) most of the ESP wells are running with downhole sensors to enhance the daily monitoring routine and for having a better knowledge of the pumps performances. However, one of the most important parameter of these ESP Wells is only known after a time period within 3-6 months: The Flow Rate. Production Tests are obtained using Multiphase Flow Testing Units which usually last between 4 and 6 hours that are also utilized to conduct some sensitivities such as choke size and motor speed changes. At Well Surveillance Group, a tailored fit model was developed from which the ESP flow rate can be estimated based on the downhole sensor data and basic fluid properties with an overall deviation below 2% (when they are compared to the results obtained from the Testing Unit). In this sense, flow rate monitoring can be performed at any time and flow testing time and associated cost can be reduced among other benefits. The method requires knowing the ESP model and total number of stages installed in the well, and then using the corresponding performance curve of the ESP model usually provided by the manufacturer, the data is processed and the calculation performed. This work aims to show how this model works, advantages, limitations, implementation status and future improvements.
A New Correlation to Calculate Oil-Water Interfacial Tension
Authors: Ling Kegang , He Jun 
Published: December 2012

Abstract
The oil-water interfacial tension (IFT) is by all means important in capillary pressure estimation and fluid-fluid and fluid-rock interactions analysis. Observations from experimental data indicate that oil-water IFT is a function of pressure, temperature, and compositions of oil and water. A reliable correlation to estimate oil-water IFT is highly desire. Unfortunately to our best knowledge no correlation that uses the compositions of oil and water as inputs is available. Our work is to fill this gap.
In this research, we collected data from former studies and investigations and developed a correlation for oil-water IFT. In the proposed correlation oil-water IFT is a function of system pressure, temperature, and compositions of oil and water. Error analysis was conducted to check the accuracy of the equation by comparing the calculated values with the experimental data. The results indicated that the new correlation predicts reliable oil-water IFTs. Our correlation calculates the oil-water IFT from system pressure, temperature, and compositions of oil and water. It addresses the effect of composition of oil on IFT, which is not presented in existing correlations. Therefore it can not only be applied in the calculation of capillary pressure in the compositional simulation, but also be used in daily petroleum engineering calculation such as waterflooding analysis.
ROP Modeling Using Neural Network and Drill String Vibration Data
Authors: Esmaeili Abdolali , Elahifar Behzad , Fruhwirth Rudolf K. , Thonhauser Gerhard 
Published: December 2012

AbstractVibrations are caused by bit and drill string interaction with formations under certain drilling conditions. They are affected by different parameters such as weight on bit, rotary speed, mud properties, BHA and bit design as well as by the mechanical properties of the formations. During the actual drilling process the bit interacts with different formation layers whereby each of those layers usually have different mechanical properties. Vibrations are also indirectly affected by the formations since weight on bit and rotary speed are usually optimized against changing formations (drilling optimization process). Therefore it can be concluded that for optimized drilling reduction of vibrations is one of the challenges.A fully automated laboratory scale drilling rig, the CDC miniRig, has been used to conduct experimental tests. A three component vibration sensor sub attached to drill string records drill string vibrations and an additional sensor system records the drilling parameters. Uniform concrete cubes with different mechanical properties were built. Those cubes as well as a homogeneous sandstone cube were drilled with different ranges of weight on bit and bit rotary speed. The mechanical properties of all cubes were measured prior to the experiments. During all experiments, drilling parameters and the vibration data were recorded. Based on analyses of the data in the time and the frequency domain, linear and non-linear models were built. For this purpose the interrelations of sandstone and concrete mechanical properties, drilling parameters and vibration data were modeled by neural networks. Application of sophisticated attribute selection methods showed that vibration data in both, time- and frequency domain, have a major impact in modeling the rate of penetration.
Automated Real Time ESP Performance Monitoring and Optimization Case Study
Authors: Khalid Al-Deyain , Rachapudi Rama Rao , Al-Mutairi Talal , Haider Bader , Mohammed Al-Yahya 
Published: December 2012

Abstract
Production from Artificially lifted (ESP) well depends on the performance of ESP and reservoir inflow. Realtime monitoring of ESP performance and reservoir productivity is essential for production optimization and this in turn will help in improving the ESP run life. Realtime Workflow was developed to track the ESP performance and well productivity using Realtime ESP sensor data. This workflow was automated by using real time data server and results were made available through Desk top application.
Realtime ESP performance information was used in regular well reviews to identify the problems with ESP performance, to investigate the opportunity for increasing the production. Further ESP real time data combined with well model analysis was used in addressing well problems.
This paper describes about the workflow design, automation and real field case implementation of optimization decisions. Ultimately, this workflow helped in extending the ESP run life and created a well performance monitoring system that eliminated the manual maintenance of the data. In Future, this workflow will be part of full field Digital oil field implementation.
Field Redevelopment Optimization to Unlock Reserves and Enhance Production
Authors: Al-Nabhani Salim , Al-Marhoon Nadhal , Al-Rubaiey Faisal , Al-Kalbani Ammar , Al-Mandhari Badar , Al-Hattali Ahmed , Al-Hashami Ahmed , Hassan Hany 
Published: December 2012

Abstract
A cluster area "H" consists of 4 carbonate gas fields producing dry gas from N-A reservoir in the Northern area of Oman. These fields are producing with different maturity levels since 1968. An FDP study was done in 2006 which proposed drilling of 7 additional vertical wells beside the already existing 5 wells to develop the reserves and enhance gas production from the fields. The FDP well planning was based on a seismic amplitude"QI" study that recommended drilling the areas with high amplitudes as an indication for gas presence, and it ignored the low amplitude areas even if it is structurally high. A follow up study was conducted in 2010 for"H" area fields using the same seismic data and the well data drilled post FDP. The new static and dynamic work revealed the wrong aspect of the 2006 QI study, and proved with evidence from well logs and production data that low seismic amplitudes in high structural areas have sweet spots of good reservoir quality rock. This has led to changing the old appraisal strategy and planning more wells in low amplitude areas with high structure and hence discovering new blocks that increased the reserves of the fields.
Furthermore, water production in these fields started much earlier than FDP expectation. The subsurface team have integrated deeply with the operation team and started a project to find new solutions to handle the water production and enhance the gas rate. The subsurface team also started drilling horizontal wells in the fields to increase the UR, delay the water production and also reduce the wells total CAPEX by drilling less horizontal wells compared to many vertical as they have higher production and recovery. These subsurface and surface activities have successfully helped to stabilize and increase the production of"H" area cluster by developing more reserves and handling the water production.
Mathematical Modeling of Shale Swelling in Water-Based Muds
Authors: Kulkarni Sandeep , Maghrabi Shadaab , Teke Kushabhau , Kulkarni Dhanashree , Jamison Dale 
Published: December 2012

Abstract
Historically, shale instability is a challenging issue when drilling reactive formations using water-based muds (WBM). Shale instability leads to shale sloughing, stuck pipe, and shale disintegration causing an increase in fines that affects the rate of penetration. To characterize shale instability, laboratory tests including Linear Swell Meter (LSM), shale-erosion and slake-durability are conducted in industry. These laboratory tests, under different flow conditions, provide shale-fluid interaction parameters which are indicative of shale instability. The composition of WBM is designed to optimize these interaction parameters, so that when used in the field the fluid helps achieve efficient drilling.
This paper demonstrates modeling of shale-fluid interaction parameters obtained from the LSM test. In the standard LSM test, a laterally confined cylindrical shale sample is exposed to WBM at a specific temperature and its axial swelling is measured with time. The swelling reaches a plateau which is characterized by a shale-fluid interaction parameter called % final swelling volume (A). A typical LSM test runs for around 48–72 hours and many tests may be needed to optimize fluid composition.
In this work, a method/model is developed to predict final swelling volume (A) as a function of the Cation exchange capacity (CEC) of the shale and salt concentration in the fluid (prominent factors affecting shale swelling). An empirical model in the form of A = f(CEC)*f(salt) which describes the explicit dependence on the influencing variables is developed and validated for 16 different shale samples at various salt concentrations. This model would significantly reduce LSM laboratory trials saving time and money. It could also enable rig personnel to obtain quick measure of shale characteristics so that WBM composition could be adjusted immediately to avoid shale instability issues.
Consideration of Voidage Replacement Ratio in Well Placement Optimization
Authors: Awotunde Abeeb A. , Sibaweihi Najmudeen 
Published: December 2012

Abstract
Determining the optimum location of wells during waterflooding contributes significantly to efficient reservoir management. Often, Voidage Replacement Ratio (VRR) and Net Present Value (NPV) are used as indicators of performance of waterflood projects. In addition, VRR is used by regulatory and environmental agencies as a means of monitoring the impact of field development activities on the environment while NPV is used by investors as a measure of profitability of oil and gas projects. Over the years, well placement optimization has been done mainly to increase the NPV. However, regulatory measures call for operators to maintain a VRR of one (or close to one) during waterflooding.
A multiobjective approach incorporating NPV and VRR is proposed for solving the well placement optimization problem. We present the use of both NPV and VRR as objective functions in the determination of optimal location of wells. The combination of these two in a multiobjective optimization framework proves to be useful in identifying the trade-offs between the quest for high profitability of investment in oil and gas projects and the desire to satisfy regulatory and environmental requirements. We conducted the search for optimum well locations in three phases. In the first phase, only the NPV was used as the objective function. The second phase has the VRR as the sole objective function. In the third phase, the objective function was a weighted sum of the NPV and the VRR. A set of four weights were used in the third phase to describe the relative importance of the NPV and the VRR and a comparison of how these weights affect the optimized NPV and VRR values is provided.
We applied the method to determine the optimum placement of wells using two sample reservoirs: one with a distributed permeability field and the other, a channel reservoir with four facies. Two evolutionary-type algorithms: the covariance matrix adaptation evolutionary strategy (CMA-ES) and differential evolution (DE), were used to solve the optimization problem. Significantly, the method illustrates the trade-off between maximizing the NPV and optimizing the VRR. It calls the attention of both investors and regulatory agencies to the need to consider the financial aspect (NPV) and the environmental aspect (VRR) of waterflooding during secondary oil recovery projects. The multiobjective optimization approach meets the economic needs of investors and the regulatory requirements of government and environmental agencies. This approach gives a realistic NPV estimation for companies operating in jurisdiction with requirement for meeting a VRR of one.
Enhanced Model for Bottomhole Pressure Prediction While Performing Underbalanced Drilling Operations
Authors: Aladwani Faisal A , Gray Kenneth E 
Published: December 2012

AbstractThe success of recent applications in underbalanced drilling (UBD) and managed pressure drilling (MPD) has accelerated the development of technology in order to optimize drilling operations. The increased number of depleted reservoirs and the necessity for reducing formation damage has also increased the need to apply UBD/MPD to such candidate fields. Several methods used the latest mechanistic multiphase flow models in order to predict bottomhole circulation pressure when performing UBD/MPD operations. A new model is developed that utilizes the latest mechanistic multiphase flow models; the developed model calculates the bottomhole circulation pressure as a function of surface injection rates, choke pressure and time.The developed model can be used in designing and optimizing UBD/MPD operations in terms of determining the correct injection rate and/or choke pressure. In addition, the developed model is used to utilize the reservoir energy to attain correct bottomhole conditions. The developed model in addition to utilizing the latest mechanistic models also reduce the error in calculating the bottom hole pressure by incorporating an algorithm in which the injection rates are calculated in-situ rather than assuming constant injection rates.The model is validated against data from literature and against a commercial simulator. Results show that the developed algorithm has increased the accuracy in predicting bottomhole pressure by incorporating the changes in new gas and liquid injection rates.