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Journal of Law

Volume : 1 Issue : 2 2013

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Author :M.A. Abedi and M.K. Algharaib
Discipline :

Optimization of Polymer Flood Performance by Preflush Injection - Numerical Investigation
Currently, many reservoirs in the region approach the end of primary recovery phase where new techniques are needed to enhance recovery. Therefore, the need to optimize oil recovery from the current resources is very well understood by regional oil companies. To enhance oil recovery from current oil resources, field operators need to overcome the forces responsible for oil entrapment. Enhanced Oil Recovery techniques (EOR) introduce new energy into oil reservoirs to reduce the influence of these forces. Most of these resources contain light oil and are considered suitable candidates for either miscible or chemical EOR techniques. The first technique is challenged by the availability of suitable miscible gas. While, chemical EOR techniques are challenges by the high salt concentrations in the maturing oil reservoirs. The high salinity conditions encourage deficiencies in the performance of chemical EOR processes. Therefore, minimizing the effect of in situ salt on the injected chemical would impose tremendous improvement that leads to higher oil recovery. One way to diminish salt effect is to condition the oil reservoirs by injecting a slug of preflush water prior to chemical injection. In this paper, the performance of polymer flooding, after preflush slug, in high salinity reservoir is investigated by numerical simulation means. The injected slugs, both preflush and polymer, are driven by water. The objective is to identify the relationship between preflush, polymer, and drive water characteristics and oil recovery. Seven parameters were considered: preflush slug size, preflush salinity, polymer slug size, polymer concentration, polymer slug salinity, and drive water salinity. The results show that these parameters have various degree of influence on oil recovery. For example, increasing the preflush slug size would results in more oil recovery especially during the early time. Detailed findings will be presented in the paper.

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Author : A. Dehghan Khalili, Sefer Yanici, Yildiray Cinar and Christoph H. Arns
Discipline :Reservoir Characterisation

Formation Factor for Heterogeneous Carbonate Rocks Using Multiscale Xray-CT images
Resistivity measurements play a key role in hydrocarbon in place calculations for oil and gas reservoirs. They are a direct indicator of fluid saturation and connected pore space available in the formation. Carbonate rocks, which host around half of the world’s hydrocarbons, exhibit a wide range of porosities with scales spanning from nanometres to centimetres. The often significant amount of microporosity displayed by Carbonate rocks emphasizes the necessity of an adequate characterization of their micro-features and their contribution to hydrocarbon in place. In this paper we examine upscaling methods to probe formation factor of a fully saturated carbonate sample using an X-ray CT based numerical approach and compare to experimental measurements. Three-dimensional high-resolution X-ray CT enables the numerical calculation of petrophysical properties of interest at the pore scale with resolutions down to a few microns per voxel. For more complex and heterogeneous samples an accurate calculation of petrophysical properties is challenging, since the required resolution and a sufficient field of view cannot be obtained simultaneously and an integration of measurements at different scale is required. In this study a carbonate sample of 38mm in diameter was scanned using the X-ray CT method with a resolution of 26μm. After accompanying experimental measurements on the full plug, four 5mm plugs were drilled vertically from this sample and X-ray CT images of these plugs acquired at resolutions down to 2.74 μm. The high-resolution images allow to access porescale connectivity, the calculation of permeability at the pore scale, followed by upscaling. Permeability was the subject of a previous study, while this work considers formation factor in a consistent framework on the same sample. We calculate the porosity of the sample (macro- and micro-porosities) directly from the images and predict the formation factor of the 2 sample at several scales using a Laplace solver. The formation factor is initially calculated by using a general value of m=2 as cementation factor for micro-porous voxels. We compare to experimental measurements of formation factor and porosity both at the small plug and full plug scale and find good agreement. To assess the degree of uncertainty of the numerical estimate, we probe the extent of hetero-geneity by investigating the size of a representative elementary volume (REV) for formation factor. We find that for the considered heterogeneous carbonate sample, formation factor var-ies considerably over intervals less than a centimetre. This variation can be explained by dif-ferent cementation exponents applied at the micro-voxel scale, with the exemption of one plug, for which the cementation exponent would have to be unreasonably low. These cemen-tation factors are derived by direct comparison between numerical simulation and experi- ment. We conclude that for one plug an error in experimental measurement might have oc-curred. The numerical approach presented here therefore aids in quality control. Excluding this plug in the upscaling procedure improves the agreement with the experimental result for the whole core while still underestimating formation factor. Allowing for a constant m=2 in the simulation at the small scale and using directly the resulting relationship between porosity and formation factor in the upscaling process leads to an overestimation of formation factor.

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Author :A.V. Alexeyenko, I.A. Adebiyi, K.M. Bartko, O. Faraj and C. Campo
Discipline :Unconventional Resources

First Shale Gas Experience In Saudi Arabia - Lessons Learned
Influenced by the success of shale gas production worldwide and to meet requirements for clean energy supply, a multidisciplinary team of petroleum specialists was established in Saudi Aramco. Meeting the growing requirement in industrial consumption and especially electricity production is a driving force for developing unconventional gas reserves. “The initial focus is in the northwest and in the area of Ghawar, where gas infrastructure exists. Initial knowledge building from similar plays in North America is being supplemented with internal technical studies and research programs to help solve geological and engineering challenges unique to Saudi Arabia and to locate specific wells planned for 2011. The company is innovatively combining knowledge and research to maximize gas reserves and production from conventional and unconventional resources in order to meet growing domestic demand” (1). During years 2010 – 2011 major international petroleum industry players – Schlumberger, Halliburton and Baker Hughes – were invited to share their experience in a series of workshops held in Dhahran. Exchange of expert ideas developed into appreciation of complexity of the shale gas reservoir and helped to identify the scope of work for the first Silurian Qusaiba shale gas well. The SHALE-1 well was drilled in 2007 as a gas exploration well. Recent drilling and geophysical data obtained in the well were beneficial for detailed sidetrack and fracture stimulation design. The Multidisciplinary Saudi Aramco - Halliburton SHALE-1 task group was established and positioned in Dhahran. This allowed them to have regular face-to-face meetings and improve the most critical criteria of any new venture – communication. The draft work plan was developed 8 months before actual operations commenced on the well site. Thorough examination of the draft work plan progressed to the final work plan with a number of improvements. For example, “R” Nipples were dropped from the monobore 4-1/2” completion string. The Frac Stimulation design was fine-tuned, involving expertise from Saudi Aramco and Halliburton. The Complete Well on Paper exercise involved over 25 specialists from both companies and helped to rectify remaining completion/stimulation design issues, and put everyone on the same page in terms of the work program. Well site operations commenced in May 2011; the well was successfully re-entered and window cut in 7” liner. An S-shaped 5-7/8” hole was drilled in the direction of minimum horizontal stresses, to the required depth in Qusaiba Shale with a maximum DLS of 4°. The well was completed with a 4-1/2” cemented liner and monobore 4-1/2” string to surface. The Hot Qusaiba interval was perforated, frac stimulated with mixed results, and successfully flowed. A temporary isolation ceramic (easily drilled) plug was set above the perforation interval. The Warm Qusaiba interval was perforated, successfully frac stimulated, and flowed with mixed results. Finally, the plug was drilled out with CTU and both intervals flowed and required production log runs were made. All targets set for the SHALE-1 re-entry well were successfully achieved and the well was suspended for future utilization as an observation well.

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Author :Salim Al-Nabhani, Nadhal Al-Marhoon, Faisal Al-Rubaiey, Ammar Al-Kalbani, Badar Al-Mandhari, Ahmed Al-Hattali, Ahmed Al-Hashami and Hany Hassan
Discipline :Reservoir Management and Economics

Field Redevelopment Optimization To Unlock Reserves And Enhance Production
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.

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Author :Tianyiu Liu, Matteo Marongiu-Porcu, Christine Ehlig-Economides and Michael J. Economides
Discipline :Reservoir Management and Economics

A Study of Transversely vs Longitudinally Fractured Horizontal Wells in a Moderate-Permeability Gas Reservoir
Transverse fractures created from horizontal wells are a common choice in tight and shale gas reservoirs. Previous work has shown that proppant pack permeability reduction due to non-Darcy flow in a transverse fracture from a horizontal well causes significant reduction in the fracture performance when the gas formation permeability exceeds 0.5 md. There are other configurations and architectures such as aligning the well trajectory with the fracture, either by drilling horizontal wells in the direction that results in longitudinal fractures or by just sticking with drilling vertical wells. However, when drilling and fracturing costs are considered, productivity is not the only optimization consideration. The field example illustrates a case when the apparent choice to use transverse fractures from horizontal wells proved to be suboptimal from the productivity perspective, but fundamental considering economics. Parametric studies for permeability ranging from 0.01 to 5 md illustrate the importance of economics in addition to physical performance. For similar reservoir characteristics, the optimum fractured well architecture varies considerably, and therefore an extensive reservoir engineering approach may be necessary beyond the well completions and/or current prejudices and inadequate understanding.

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Author :Xu Anzhu, Mu Longxin, Zhao Lun, Fan ZIfei, Yang Xuanyu and Xue Xia
Discipline :

A New Strategy of Well Pattern Design and Adjustment to Enhance Production of Oil Fields with Vertical Multiple Series of Reservoirs
The well patterns and pattern types of well placement issue in a productive formation is an important aspect of the effective field development. The problem solution is impossible on the intuitive level due to the reservoir inhomogeneity. At present the well pattern is accepted to be located basing on the famous criteria, specialist experience and hydrodynamical simulation on a reservoir model. The designer should analyze many field development variants with different well spacing during limited time interval. The adjustment of large-scale multiwell field-development projects is challenging because the number of adjustment variables and the size of the search space can become excessive. This difficulty can be circumvented by considering well patterns and then optimizing parameters associated with pattern type and geometry. In this paper, we introduce a new framework for accomplishing this type of adjustment for vertical two or three reservoirs.The development of vertical multiple reservoirs were usually by a separate well pattern for every reservoir, or through reservoir-by-reservoir from bottom to top by only one well pattern. A separate well pattern for every reservoir requires drilling many more wells and higher investment costs, while development through reservoir-by-reservoir from bottom to top by one well pattern made oil recovery rate and development efficiency very low and uneconomic. Consideration on fully developing every reservoir well efficiently, firstly, an inverted-nine well pattern was designed for every reservoir and the well space was L (L was defined as an optimal well space for respective reservoir) and the distance between adjacent well patterns was L. Secondly, all wells were drilled to the bottom of the lowest reservoir. Thirdly, when average water-cut of producers in every two well patterns was greater than 80%, the two well patterns interchanged reservoirs. Finally, when all reservoir interchange was completed, every reservoir was developed by the new equivalent infilled well pattern with well space of L. The adjustment strategy made the required number of drilling wells in the whole field can be reduced by 50% and achieved better development effect. This strategy was put into practice on North Buzachi oil field in Kazakhstan and average oil rate of single well was increased by 20%, oil recovery rate has an increment by 12 percent, the recovery factor was increased by 6.7%, economic profit is 1.8 times that of one separate well pattern for every reservoir, the effect was perfect. This work analyzed the performance of this new strategy of well pattern design and adjustment to effectively develop vertical multiple series of reservoirs and the methods to determine the reasonable time of two well patterns interchanging reservoirs through simulation study and current application effects.

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Author :Mohammad A.J. Ali, S.M. Kholosy and A.A Al-Haddad
Discipline :

Laboratory Investigation of Dynamic Growth of Asphaltene Deposition and Formation Damage on Sandstone Cores
A live oil sample was subjected to a solid detection system (SDS) to measure asphaltene onset point (AOP) at 3850 psi, and asphaltene content of 1.3%. A high-resolution digital camera was used to measure asphaltene particle size distribution. The result showed that asphaltene particles were not uniform in size, but has a normal distribution of 100-120 µm. Asphaltene reversibility to dissolved back into the oil with increasing pressure was only 35% of the original deposition. Two core samples were examined for formation damage due to asphaltene deposition. A Low permeability core showed significant permeability reduction exceeding 50% of its baseline permeability, and the higher permeability core showed less permeability decline, even with the same asphaltene precipitation.

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Author : Mohammad S. Al-Kadem, Faisal T. Al-Khelaiwi and Meshal A. Al-Amri
Discipline :Intelligent Oilfields

Real-Time Estimation of Well Drainage Parameters
The well drainage pressure and radius are key parameters of real-time well and reservoir performance optimization, well test design and new wells’ location identification. Currently, the primary method of estimating the well drainage radius is buildup tests and their subsequent well test analysis. Such buildup tests are conducted using wireline run quartz gauges for an extended well shut-in period resulting in deferred production and risky operations. A calculation method for predicting well/reservoir drainage pressure and radius is proposed based on a single downhole pressure gauge, flowing well parameters and pressure-volume-temperature (PVT) data. The proposed method uses a simple approach and applies established well testing equations on the flowing pressure and rates of a well to estimate its drainage parameters. This method of estimation is therefore not only desirable, but also necessary to eliminate shutting-in producing wells for extended periods; in addition to avoiding the cost and risk associated with the wireline operations. The results of this calculation method has been confirmed against measured downhole shut-in pressure using wireline run gauges as well as dual gauge completed wells, in addition to estimated well parameters from buildup tests. This paper covers the procedure of the real-time estimation of the well/reservoir drainage pressure and radius in addition to an error estimation method between the measured and calculated parameters. Furthermore, the paper shows the value, applicability and validity of this technique through multiple examples.

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Author :Hadi Belhaj, Abdulla Aljarwan, Mona Yousif Al Ali and Nader Abdulkadir
Discipline :Reservoir Management and Economics

Future Oil Prices, Where to? A Systematic Modeling Tool for Decision Makers
The global economy continues its journey of evolution and progression driven by industrialism as its primary force. With such a fast pace of development and recoveries from several recessions through the many years, dependency on energy sources became inevitable to satisfy the rising demand. This paper represents a proposed global energy price model that has the flexibility of modeling the energy price, using data of specific regions of the world, as well as the global energy pricing equation. The ANM (Alternate Novel Model) is presented here. The model focuses mainly on oil price modeling, since the oil accounts for more than 84% of the current world supplied energy. The model duration is 50 years; starting from 1980 to 2030, model matching period from 1980 to 2011, and the prediction period is from 2012to 2030. The modeling approach used in ANM adopts weighted averaging of individual factor and it relies on line regression technique. Therefore, future trends are being predicted based on the cyclic nature of the market and historical data “the future is reflection of the past”. ANM can then predict the futuristic oil price, depending on the factors and variables that have been placed in the process for the output results. The paper aims to propose a reliable model that accounts for most governing factors in the global energy pricing equation. All steps followed and assumption made will be discussed in details, to clarify the working mechanism for this model and pave the road for any future updates.

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Author : M. Majeed and S.M. Al-Khaledi
Discipline :Production Operation and Facilities

Developing High H2S Facility Design Requirements in Conceptual Stage
In order to develop the design requirement with current regulatory and contemporary HSE practices, for a typical sour oil/gas production facility, a hypothetical case of about 3 mol % v/v H2S in gas and 300 ppm w/w H2S in oil, of multiphase feed stream, has been studied through the dispersion modeling for the conceptual stage. The findings indicated credible downwind lethal / semi lethal threat distance up to 300 meters. The conclusions of the H2S toxic risk assessment combined with the inherent safe design guidelines have yielded an entirely new set of requirement for the risk reduction. To start with it was realized that safe distance control room should be constructed and facilities should be designed for the remote operation, utilizing the new trends of foundation field bus, electronic marshaling and SIL-3 fiber optic sensors. The facility should be access controlled with mandatory PPE requirement of personal H2S monitors and personal quick donning (5 sec) escape SCABA (15 minutes capacity). The centrifugal compressors should be new generation design of enclosed and hermetically sealed type, levitated with magnetic bearing, without dry gas seals and oil lubrication. The vessels should be ASME Section VIII “lethal service” design and plant piping should be as per fluid category “M” of ASME B31.3 chapter VIII. Furthermore, stress relieving for thicknesses as low as 10 mm, rather than ASME B31.3 code specified >19 mm would be required. Small valves < 4” sizes should be of forged steel instead of cast steel. The export oil/gas pipelines and flow lines should be designed for <= 50~60 % of SMYS. Plate instead of Shell and Tube Exchangers. Adequate margins between vessels design and operating pressures to avoid PSV chattering. The PSV’s to have acoustic monitoring. The facilities should be designed free of valve pits and internal corrosion monitoring pits.

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Author :Lucas R. Moore, Cynthia Cardoso, Marcelo Costa, Amir Mahmoudkhani and Laura Sanders
Discipline :Environment, Health, and Safety

Removal of Total Organics and Grease from Oil Production Effluents by an Adsorption Process
Oilfield produced water accounts for 98% of all waste generated in oil and gas exploration and processing. This process water may contain up to 1000 ppm total oil and grease, which must be treated prior to discharge. A novel inorganic adsorbent was designed to have high affinity towards such organics. Lab scale evaluations of this adsorbent on production effluents obtained from an onshore site consistently yields TOG removal > 96%. This was found to be a significant improvement over the chemically assisted DAF at 74% in similar lab scale evaluations. This novel technology has the potential to provide a substancial reduction in capital and operating costs for water treatment.

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