bluuebunny/crossref_metadata_2025_split huggingface dataset:
Modelling of a Large Depleted and Tilted Carbonate Oil Rim Reservoir - An Integrated Case Study from UAE
Authors: Kundu Ashish , Voleti Deepak Kumar , Mokhri Mohd Nazaruddin , Manseur Saadi 
Published: November 2017

Abstract
When a reservoir undergoes gas cap production without proper pressure maintenance, the underlying oil rim development at a later stage of the field development is very critical and challenging. Adding to the complexity is the tilted Free Water Level. This paper presents a study that was performed to model a large tilted oil rim reservoir that had been massively depleted by the production of the overlaying gas cap.
The first part of the paper explains the development history of the oil rim and the low recovery factor that was obtained as a result of the massive gas cap depletion, and the results of previous attempts to revive dead oil wells through artificial means (ESP, booster pumps) which had limited success so far. The second part of the paper elaborates on the study which was carried out to build the concept of a tilted reservoir and later modelled it to get the proper initial water saturation distribution. The variable salinity concept was brought in to validate the proposed tilting scenario. The variable salinity was supported by produced water salinity data. The formation pressure test data also conforms to the tilting concept.
The tilting in Free Water level (FWL) was also observed while analyzing capillary pressure data. Model was prepared to map the tilted FWL by krigging FWL depths at individual wells. The challenges that were encountered and overcome during the feasibility study: (1) construction of a new reservoir model incorporating a large set of static and dynamic data showing significant complexity with tilted fluid contacts, variable formation water salinity and initial fluid saturation; (2) multi-scenarios history matching with complex fluid movements and tilted Free Water Level; (3) reservoir uncertainty analysis using learnings from history matching; (4) accurate remaining oil saturation in oil rim.
The originality of this study resides in the complex reservoir geology and field production history, in the integrated approach to address requirements of both oil rim and gas cap developments, and in the fact that proposed field revitalization calls for unusual static and dynamic reservoir property modelling which can conceptualize the fluid movement before and after production.
Integrated Asset Modelling Unlocks Reservoir Deliverability and Maximizes Asset Value in a Middle East Digital Oil Field
Authors: Rubio Erismar , Figuera Luis , Khan Karem , Davila Rayner , Amro Ahmed Abdulla , Tazerout Kahina , Rusmantoro Achmad , Emam Ahmed Mohamed 
Published: November 2017

Abstract
Historically, field development plans are determined by reservoir production profile generated in standalone subsurface models using a simulation-based forecast. The resulting oil production profile is commonly over estimated because the constraints imposed by the infrastructure capacity on the surface network are not captured appropriately. Moreover, reservoir simulation engineers are forced to apply many simplifications to represent the backpressure impact of topside facilities over the reservoir deliverability. A common practice is to constrain the model, assigning the same minimum bottom hole pressure or well head pressure to all wells and thus misrepresenting the actual wells' behavior. In general this approach may lead into poor development plans, suboptimized system designs, incorrect budget estimation, over expenditures, and so on; all of these issues will impact the overall asset performance and hydrocarbon recovery. Integrated asset modeling (IAM) is a holistic approach that allows upstream and downstream components to be modeled together in order to accomplish a comprehensive production forecast on truly surface constraints.
This paper contains a smart field case that demonstrates how coupling subsurface and surface models can effectively improve production forecast accuracy and leverage production optimization from well to asset level in order to provide decision support that takes into account the complexities of interactions between upstream and downstream domains. This work addressed problems such as: the impact of fluid composition variation over time, the interdependencies between wells sharing facilities, the effect of the production strategy or reservoir guidelines over total field production when multiple reservoirs are connected to a surface network sharing common capacity constraints, and optimization of the artificial lift strategy in place. After economical evaluation, it was possible to redefine a development plan considering surface constraints and actual production profiles that optimally extent production plateau for the next 10 years.
The value of having an IAM is that it allows for the evaluatuation of the relative impact of downstream and upstream interdependencies over time, thus enabling comprehensive assessment of a wider range of scenarios and development opportunities. This is turn shall contribute to maximize asset profit and generate opportunities to sustain production based on economic and financial indicators.
Scrutinize Logging While Drilling Data in Horizontal Wells: Reservoir Architecture & Fluid Fill Alternative Concepts Aids in Realizing the Potential of Flank Infill Opportunity in the Sultanate of Oman
Authors: Hadidi Shahab , Ferrero Maria Boya , Yaarubi Hilal 
Published: November 2017

Abstract
The infill potential of a waterflood project in a transition zone carbonate reservoir has been revised through the usage of logging while drilling (LWD) data in horizontal wells. The North-Western flank prospective has been unlocked by unravelling lateral variations on reservoir architecture and generating an alternative fluid fill concept for transition zone saturation.
The field is developed through horizontal wells with only five vertical penetrations that are clustered in the southern part of the field. Data analysis of the vertical wells supports the log response calibration, relating architecture and fluid fill to saturation models. The high density LWD data allows the coverage of the North Western flank. An alternative fluid fill scenario related to tectonic structural changes after charge (as previously published in 2016, SPE 181401) is consistent with vertical wells and LWD data and reflects an upside for the North-Western flank saturation.
The alternative fluid fill concept reflecting post-charge tectonic changes of the structure has improved the North-Western flank saturation and infill potential. With the alternative concept, now in alignment with actual LWD measurements, the history match of the oil production of the flank sector has been achieved. An appraisal well is planned to assess the potential of the area.
Laser Perforation: Lab to the Field
Authors: Batarseh Sameeh I. , Graves Ramona , San-Roman-Alerigi Damian P. , Chand Karam 
Published: November 2017

Abstract
This objective of this work is to improve well perforation by using non-damagingsafe (non-explosive) high power laser perforation technology. For several years of research, high power lasers have been proven in the lab to create controllable perforation tunnels with enhanced flow properties. This paper presents the strategy of lab to field transformations to perforate horizontal well with two inches in diameter by twenty four inches deep at 10,000 feet in horizontal well.
High power laser is an alternative and innovative technology to currently used shaped chargeperforation. Lasers are advanced in several industries for their several unique properties such as power, precision, control and reliability, with these properties; controllable non-damaged enhanced oriented perforated tunnels are achieved. Laser power can be adjusted precisely to control the depth of the tunnel; the tool can be oriented to create perforation in any direction regardless of the reservoir stress orientations as lasers are stress independent.
Shale, Sandstones (including tight sandstones) and carbonate rocks have been perforated at different conditions, the result from all rock types showed improvement in permeability and creation of controlled geometry without any compactions or damage. The success of the lab experiments lead to field deployment strategy to create the first in the industry laser perforation at 10,000 feet. Lab to field transformation is presented at different stages, first prove of concept, then design and test lab prototype tool, followed by improved field upscale downhole tool.
High power laser in downhole is a safe (non-explosive) perforation technology. The geometry, depth and orientation can be controlled very precisely to create clean enhanced perforated tunnel. With a single trip, several perforation shots can be made withoutthe need to load and unload the perforation tool. Laser source is mounted on the surface on a coiled tubing unit and the beam is transmitted via fiber optics cable totarget, the compact design of the tool make it suitable to fit in any slim hole.
East Abu-Sennan Gas Plant Planning and Construction Challenges
Authors: Alsawi K. , Abdelmonsef M. , Atwa M. , Hegazy M. 
Published: November 2017

Abstract

Objectives/Scope
Kuwait energy company has started to explore and develop oil and gas reserves since 2010 in East Abu-Sennan concession under production sharing agreement with the Egyptian General Petroleum Corporation. This concession is located in the Western Desert of Egypt, Production was commenced in July 2012 with 4 wells, oil production in this field was restricted due to gas flaring limitations in the agreement to 1 MMSCF/Day.
Therefore, Kuwait energy initiated a challenging objective for the best gas utilization method in 2014. The project to be executed must pass the barriers of economic model with pessimistic reserve inputs and relatively short execution duration.

Methods, Procedures, Process
Three scenarios were considered for Gas compression station: Brand new equipment, Rental Facility and Idle Used equipment. Risk assessment and economical modeling were performed and showed that Idle Used equipment existing in the country is the most economically feasible option.
16 years old idle equipment were located within EGPC custody, onsite inspection and data collection to determine efficiency and repair requirements followed by engineering work to recheck design calculations and HAZOP Studies. Equipment manufacturer agents performed the overhauling for rotating parts and upgrades for electric control panels. Meanwhile a two-phase agreement with a qualified contractor was initiated for dismantling the equipment inside active plant, transportation and installation in the project location.

Results, Observations, Conclusions
The project was completed and commissioned within allocated budget and time frame of 6 months leading to increased average daily production from 1,864 BOEPD in 2014 to 5,988 BOEPD in 2015 in addition to zero flaring target achievement. The plant has been running for more than two years without any failures or shut downs.

Novel/Additive Information
From this project planning, execution and results; we can claim that if Risk assessments, detailed scope of work, time management with contractors/suppliers and cost effective choices were addressed carefully; shall result in outstanding performance.
Smart Well Completion Optimization in Multilateral Wells
Authors: Arukhe J. O. , Khelaiwi F. , Isichei O. , Dhubaiki A. A. 
Published: November 2017

Abstract
The ability of smart well completions (SWCs) to best function as intended in the field, has led to renewed focus on smart well completion optimization opportunities. The action of inflow control valves (ICVs) is key to improved management of flux imbalance and premature production delay of unwanted fluids from contributing laterals of the intelligent wells. Difficulty with the use of ICVs includes the complexity to determine all possible combinations of valve settings (given 11 possible positions per valve on each lateral). Imposing specific wellbore pressure profiles in dual or trilateral well completions, to control production, or achieve pressure responses within ideal electrical submersible pump (ESP) operational ranges for continuous uninterrupted functioning of the smart wells is even more challenging. Real-time data acquired during SWC tests at various combinations of valve positions was modelled to determine contributions from motherbores and/or laterals in 11 smart wells. The ICV positions and surface chokes were controlled, while flow rate, wellhead pressure/temperature, and intake pressure/temperature were measured. From the tests, the optimal settings for individual or commingled flow were determined in real time from the network models (objective functions include minimizing water, maximizing oil, subject to staying within effective ESP intake pressures). Tests showed wells with up to 34% and 57% basic sediment and water (BS&W) from the motherbore and lateral respectively and corresponding normalized rates of 1.539/1.138. Implementing results of the model resulted in a normalized oil gain of 3.800 and 27% BS&W reduction from both laterals. The model yielded the optimization parameters, which resulted in choking back drainage points to achieve the water cut reduction and realize the oil gain. Test data revealed an accuracy of more than 90% match between calculated and measured flow rates of targeted drainage points. The results confirm that modeling ICV completions to determine optimum valve positions and rate targets is possible for an entire SWC or specific laterals.
Origin of Complex Carbonate Pore Systems and Associated Reservoir Quality Variations: an Example From the Arab Formation Upper Jurassic, Onshore United Arab Emirates
Authors: Hollis C , Lawrence D , Darmaki Fatima Al , Perriere Matthieu Deville , Foote Alexander , Kostic Boris 
Published: November 2017

Abstract
This paper summarises the results of an intense reservoir appraisal programme that was conducted within a sour gas reservoir, onshore UAE, in order to determine the controls on porosity presence, distribution and effectiveness. This multiwell study was conducted over less than 5 years in order to define and predict porosity sweet-spots, and prepare for first gas, which was achieved in 2015. Focus is on the Arab D Member of the Arab Formation, the thickest and volumetrically most significant reservoir interval. It comprises an upward-cleaning succession of lime mudstone, peloidal and skeletal packstone and oolitic grainstone, culminating in a clay-rich, brecciated emergent surface. The entire succession shallows upwards from very low energy, basinal mudstones into cross-bedded oolitic grainstones that were deposited in a shoal complex that protected a gently agitated lagoon. Low skeletal diversity and the abundance of ooids are indicative of slightly elevated salinities; the abundance of anhydrite within the overalying Arab A/B/C and Hith Formation is indicative of basin dessication.
The lowermost Arab D Member is dominated by lime mudstones and is highly microporous. A very low matrix permeability is locally enhanced by short, partially cemented, vertical fractures formed perpendicular to stylolites, usually cutting thin skeletal floatstone beds with abundant biomoulds. The main reservoir interval is the overlying upper Arab D Member. Porosity occurs principally as intraparticle micorporosity in ooids but in the uppermost upper Arab D Member, interparticle cement volumes are lower and macropores are preserved. The best reservoir properties occur within this bioturbated oolitic grainstone facies, and in cross-bedded oolitic grainstone near the palaeo-crest of the field, probably because early oil emplacement inhibited cementation. There is good evidence that the base of the upper Arab D Member and the lower Arab D member are in communication. Although there is evidence of thermochemical sulphate reduction in the Arab D Member, it is volumetrically minor and unlikely to have generated the high volumes of H2S that are known to occur in the field.
Waterless Stimulation for Unconventional Resources: An Alternative to Conventional Water-Based Fracturing Techniques
Authors: Cui Weixiang , Cui Mingyue , Wang Chunpeng , Liang Chong 
Published: November 2017

Abstract
Compared with hydraulic fracturing, waterless fracturing can alleviate pressure on water resource significantly. Studies have been made to the LPG waterless fracturing, waterless fracturing with liquid CO2, high-energy gas fracturing and cold fracturing with liquid N2, to identify the feasibility of these technologies with lower operation costs. It is believed that new environment-friendly fracturing technology is expected in the future.
Among the existing waterless fracturing technologies, waterless fracturing with liquid CO2 is the most feasible one with safe and efficient performance. CO2 is a kind of ideal fracturing fluid, which is easy to liquefy, safe and non-explosive. CO2 fracturing can efficiently stimulate the reservoir, without damage to the reservoir and with less water consumption. It is qualified for operation in view of energy conservation, emission reduction and environmental protection. This technology is significant for clean and efficient development of low-permeability tight oil reservoirs, and worthy of broad application.
CO2 fracturing technology is one of the waterless fracturing technologies. It has the advantages of water free, low reservoir damage, and production increase by improving the reservoir pressure. However, the technology faces the challenges of low viscosity of liquid CO2 and difficulty to pump proppant. No conventional thickening agent can provide the required thickening in 100% liquid CO2. In this paper, the problem of thickening gelled liquid CO2 has been solved by developing a new surfactant and thickening agent. Surfactant additive agents can make the liquid CO2 gel by forming wormlike micelle or cylinder micelle structure. The cylinder micelles enhance the viscosity through entanglement inter-action above a critical concentration. By a high pressure pipeline rheological experimental device, the effective viscosity of liquid CO2 gel fluid is between 7.654 – 20.012mPa.s, and the viscosity of liquid CO2 increases by 95 to 498 times under the same conditions.
The new liquid CO2 based gel fracturing fluid has been used in five wells of Jilin Oilfield in China, during the fracturing, 19.8 m3 of proppant was successfully pumped to the reservoir in one well, at a mean proppant concentration of 6.8%, as a result, the production of them has increased by over 100%. With low viscosity and high diffusion coefficient, supercritical CO2 is good for improving fracturing volume. Effective CO2 fracturing technology can improve stimulated reservoir volume, downhole monitoring results show that the cracks formed by CO2 fracturing is 2.6 times the size of those formed by water-based fracturing.
Successful Production Enhancement for Carbonate Gas Reservoirs by Under Balanced Coiled Tubing Drilling Using Production and Seismic Data
Authors: Lu Hanyu , Al-Faleh Khaled F. , Al-Omair Ahmed M. 
Published: November 2017

Abstract
This paper discusses the innovative method of production enhancement with under balanced coiled tubing drilling (UBCTD) by using production and seismic data to steer in carbonate gas reservoirs.
Certain carbonate reservoirs lack of microfossils to identify the productive layers, which makes it challenging for UBCTD operation to steer in such reservoirs by just analyzing the cutting samples without real time logging. A new method is applied to place wells in porous and productive layers with the help of production and seismic data. During drilling, gas production is monitored in real time and analyzed with productivity index. Good production zone is identified with increasing productivity index and linked with acoustic impedance (AI) from seismic data which helps to steer in productive layers.
Such approach helps UBCTD operation to identify and stay in the good production zone in real time, increasing the certainty of well placement due to carbonate reservoir heterogeneity and maximizing the production contribution from drilled footage. Wells can be drilled without cutting sample analysis or real time logging, reducing operation cost and risk of stuck logging tool. Overall, extended reservoir contact can be reached with minimum formation damage and therefore production is enhanced substantially. At the end of the UBCTD operation, production potential is assessed during the flowback to clean up drilling fluid. No further rigless stimulation job is required and wells can be put on production immediately after drilling completion.
The benefits of such optimized method is evident in the outstanding gas production from the drilled wells. This provides an efficient alternative to enhance production from carbonate gas reservoirs with better economic feasibility.
Successful Well Design Journey-Oman
Authors: Hilal Rubaiey , Mohammed Hajje , Lawati Ali Baqir , Saud Khaldi , Yan Terras , Badar Zeidi , Pranava Ananda 
Published: November 2017

Abstract
PDO, onshore, Hard rock drilling with a high UCS ranging from 25-40 KSI, associated with many challenges in deep gas fields drilling (+/− 5200 m), many wells turn to be not economical. Therefore; under the objective of improving the overall wells economics, drill more with less, while hoard guarding the current well functional requirements as well to reduce standard deviation for well delivery times; an appropriate Stair Case journey to slim design the wells with fit for purpose design taking into consideration various challenges been taken forward to prevail over and scrutinize the limitation associated with previous typical design. Slimming down the wells been brought forward to overcome the reactive shale challenges combined with severe losses zones along with hard rock drilling that results in about 3 millions USD saving per well.
This manuscript is a case history study covering the drilling practical journey that was experienced in B-field for the wells designed and finished.