bluuebunny/crossref_metadata_2025 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

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

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

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

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

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

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

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

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

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

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.
Fracture Modeling in Naturally Fractured Reservoir Using Damage Mechanics Coupled with Poromechanics
Authors: Bubshait Ahmed , Aminzadeh Fred , Jha Birendra
Published: November 2017

Presence of natural fractures in reservoirs increases heterogeneity and modeling complexity while playing a significant role on well productivity and field recovery. Placing horizontal wells in naturally fractured tight carbonate reservoirs is extremely challenging due to the large variation in the natural fracture density and consequently in the formation permeability. To enhance and maintain production from such reservoirs, hydraulic stimulation is conducted to create new fractures and activate pre-existing natural fractures. However, during production/injection periods, poromechanical properties of the fractured reservoir might change with changing pressure and stress conditions. This affects ultimate recovery and results of future well placement and stimulation efforts. Changes in the properties, such as enhancement or reduction in permeability, also complicate computational modeling and performance forecasting of the reservoir. In this paper, we propose a framework to capture such flow-induced property changes in a fractured reservoir.

Our framework is based on a sequential solution of three coupled problems: (1) mechanical deformation (2) fluid flow, and (3) fracture propagation. We use the finite element method to solve the quasi-static mechanical deformation problem, the finite volume method to solve the Darcy flow problem in the matrix, and a damage mechanics approach to model propagation of pre-existing spatially distributed fractures and the ensuing evolution in flow and mechanical properties of the reservoir. We use the fixed strain scheme to couple the mechanical problem with the flow problem sequentially. The two problems are coupled to the fracture propagation problem via stresses, pressure, elastic moduli, and permeability.

The framework allows for coupled flow, deformation and damage in fractured reservoirs without the computational burden associated with an explicit fracture representation. This means we can obtain accurate predictions in realistic scenarios of production from heavily fractured and stress-sensitive reservoirs. Modeling these processes will also help in optimizing horizontal well placement decisions.
Improved Field Development through Timely Integration of Post-Drill Analysis Results
Authors: Obeta Chukwudi , Aljaberi Fatema , Khouri Naeema , Al Zawa Hesham Abdulla , Wendland Corey , Dedmon Russell , Al Dhaleei Omar , Ottinger Gary , Shekhar Ravi , Omura Taihei , Al Zinati Osama , Abousayed Nada , Almurshidi Saja , Khan Mohammad Yunus , Attalah Khaled , Al Neyadi Abdulla , Al-Shehhi Budoor
Published: November 2017

As part of the ongoing development of a large offshore oil field, an asset owner places a strong emphasis on continuous improvement of the established framework for integrated post-drill well analysis. The geology of the candidate field is complex and the occurrence and distribution of the extreme permeability features that dictate early water production is highly uncertain. While much effort is devoted to mitigating their adverse impact through proper integration of surveillance data for accurate well planning, post-drill outcomes can still diverge significantly from pre-drill expectations. Several wells have been drilled in the production build-up campaign, including ground-breaking pilots and many more are following in very quick succession as part of the life cycle strategy for the field. Due to high drilling frequency, the challenges of assimilating learnings through conventional post-drill analysis for optimization of future drill wells can be enormous. To apply key lessons from these wells in building quick baseline knowledge for reservoir model update and drill plan optimization, the modeling and development team have developed an improved workflow for integrated post-drill analysis. The workflow leverages the full benefit of collaboration between multi-disciplinary teams to integrate 3D seismic data, multiple well information (including geologic reports, well logs and petrophysical results) and surveillance data from new drill wells to benchmark pre-drill expectations. An important aspect of the approach is the quick incorporation of drilling results into static and dynamic models via a cycled, closed-loop workflow for quick assessment of model fidelity through an evergreen update process. A multifunctional post-drill analysis facilitates critical consideration of well results to capture significant learnings that influence future drill well and data acquisition optimization, reservoir model history match and prediction enhancements, and identification of drilling hazards and geological features that affect reservoir performance. This paper describes the methodology used to plan and implement post-drill well analysis within a fast paced and high drill frequency environment. Key elements of the methodology are described through the use of a case study example, and include: Standardized subsurface workflow, comparison of post-drill well results with pre-drill well expectations, identification and documentation of significant observations and lessons learned improvement of history match & predictive capability of reservoir models and integration with other drill-well delivery processes.
Optimizing Well Design and Real-Time Drilling Operations Using a Seismic Attribute Guided Methodology
Authors: Liang Xing , Zhao Chun Duan , He Yong , Bouchet François , Liu Cheng , Wang Lizhi , Li Qingshan
Published: November 2017

This paper presents a seismic-attributes-guided method developed to assist drilling engineering both at design and execution stages.

In recent years, shale gas has been a focus of development in the Sichuan basin (southwest China). The formations are over 400 million years old; they have been affected by multiple major tectonic events during geological times. As a result, of successive stress and strain, the reservoir rocks now display a large number of small-scale faults, folds and multi-directional fractures. To maximize the value from wells, while avoiding drilling hazards, a detailed structural delineation is required for: reservoir-scale geosteering, well trajectory control and drilling risk prevention and mitigation.

Seismic is the only data available for 3D structural characterization. For an accurate result, high fidelity seismic (amplitude preserved high resolution data) is required. First a pre-stack data is selected (from gathers), conditioned and prepared as a micro cube for interpretation. Then a reservoir scale structural interpretation is carried out and a detailed structural map constructed, to analyze micro structural features from surface based attributes (amplitude, dip, curvature, etc.). In parallel multiple volume attributes are derived from the micro cube, including: variance, Ant-Tracking, apparent polarity and instantaneous bandwidth. In a final step surface attributes and volume attributes are integrated along with the planned well path to help anticipate possible drilling risk. ‘Ant-Tracking’ and ‘Seismic Discontinuity Planes’ algorithms were used to extract fault planes. The apparent polarity attribute reveals the sign of the reflection coefficient; it was found useful for delineating small events. Instantaneous bandwidth, represents the standard deviation of the instantaneous power spectrum about its mean, delineating vertical variation along the structural surface.

We were able to predict drilling risk and formation dip with the integration of seismic attributes.

The predictions were in good agreement with drilling events observed in the horizontal wells, such as: tight pull; mud loss; stuck pipe and drilling breaks. The predicted formation dip trend was confirmed. In one well, the original structural interpretation showed only one fault while the attributes analysis showed 11 faults. While drilling the well, for two of these faults, "bit drops" of 0.5m and 0.1m were observed. Only two predicted faults had no corresponding drilling event, but larger rock fragments were observed in cuttings, suggesting faulted zones may have been encountered.

This paper is based on several real-time-tracked horizontal wells, drilled with the assistance of integrated seismic attribute analysis (including particularly apparent polarity and instantaneous bandwidth).
Reducing Operational Flaring through ALARP Based Decision Making
Authors: Agrawal Harshit , Al Shuayli Mohammed , Salmani Mohamed
Published: November 2017

Long term operational flaring leads to significant loss of gas resources, impact environmental air quality, as well as affect the organization's reputation. Global benchmarks indicate that operational flaring can lead to losses of more than 2% of total oil and gas production. The objective of this study is to present an innovative decision making framework and best practice tool that enables robust cost-benefit risk analysis to be conducted for reduction of long term operational Flaring.

In this study, a state of art, user friendly assessment tool is developed to demonstrate that Flaring risk is reduced to As Low As Reasonably Practical (ALARP). This tool brings greater visibility and ownership of flaring performance by applying a consistent, value based decision making framework for operational flaring events. The framework includes process for derogation, evaluation and investigation of flaring events, taking into account the economic and environmental costs of flaring by monetizing actions such as taking a decision to defer oil production in order to avoid flaring or alternatively taking a decision to flare to maintain production.

The successful roll out of a consistent derogation process through the decision making framework and tool brings management visibility of the cumulative economic and environmental implications of short and long term operational flaring events. This shared understanding in the organization of the decision criteria and thresholds, in longer term leads to significant quantitative reduction in flaring volumes. Secondly, the methodology provides an auditable demonstration of management of Flaring risk to company's internal and external stakeholders.

Additionally, the information gathered from the derogation framework leads to the identification of corrective operability or reliability measures needed to address repetitive non-routine flaring events that will help in continuously driving improvement in longer term greenhouse gas intensity performance and gas conservation priorities.
Dynamic Wellbore and Near-Wellbore Clean-Up in Wells with a Sandface Flow Control Completion
Authors: Nikjoo Ehsan , Mammadov Rufat , Muradov Khafiz , Davies David
Published: November 2017

This paper presents a comprehensive analysis of the well performance during clean-up when the well is equipped with either autonomous, passive, or active sandface flow control completion (sFCC). Numerical modelling is used to study this performance. A few studies have investigated the clean-up performance of sFCCs, especially of the autonomous sFCCs.

The sFCC clean-up performance is modelled using an integrated, numerical simulation of dynamic flow processes in a coupled wellbore-reservoir model. The well model is first saturated with the drilling and completion fluids by considering the effect of the mud cake formation and lift-off pressure during well flow back, as well as the relative permeability hysteresis of the invaded zone. The sFCC's performance is modelled and verified using published input data. The simulations reveal how the various sFCC types differ in their clean-up performance, including:

The sFCC equipped with Inflow control devices (ICDs) can accelerate the clean-up process compared with conventional (i.e. no sandface flow control) completion. The clean-up efficiency of this sFCC type rests on balancing the positive effect of the more uniform inflow profile along the completion and the negative effect of imposing a higher pressure drop across the completion. The sFCC equipped with Interval control valves (ICVs) allows sequential clean-up of the well zones, where the clean-up of each zone can be optimised separately. Finally, the clean-up performance of the sFCC with autonomous flow control devices (AFCDs) is more complex being highly sensitive to this sFCC's design, the extend of the invaded zone, the wellbore trajectory and etc.

Finally, a generic discussion on how to possibly improve the sFCC clean-up is presented. This work improves our understanding of the clean-up performance of wells with sFCCs.
Automated Catwalk Machine for Land Rigs
Authors: Loeyning Trond
Published: November 2017

In the land drilling market there is a lack of versatile catwalk machines. The tradition of having various models for each rig type and drill floor heights makes the typical catwalk machine inflexible. As an answer we have developed a complete new catwalk machine that suits a great variety of rig types and drill floor heights, and the unique design optimizes the angle the pipe enters into drill floor. In addition the optional crane function ensures catwalk versatility and simplifies handling of objects between ground level and drill floor.

Automated operations will lead to self-running operations and ultimately an autonomous drilling operation, thereby allowing drillers to optimize safety and performance. This automated catwalk provides a mechanization that allows remote automatic operation to enable workerless handling of tubulars from ground level to the drill floor. Through our unique design we will not only transport tubulars from ground level to drill floor, but provide a safe and efficient way of handling objects such as stabilizers, subs, bits, and pups between ground level and the drill floor simplified through use of an optional integrated manipulator arm.
An Integrated Approach to Optimize Monthly Production Allowable in a Giant Offshore Field
Authors: Zhao Wenyang , Al-Neaimi Ahmed Khalifa , Saif Omar Yousef , Al-Feky Mohamed Helmy
Published: November 2017

To optimize oil production and improve operating efficiency is always pursued by oil operating companies. It is a very challenging practice to achieve an optimum monthly production plan, especially for a mature oil field with limited surveillance data and increasing challenges. As one of the biggest offshore fields in the world, it has more than 350 oil production strings and more than 200 injection strings. Complicated fluid movement, unevenly pressure support, and no available artificial lift methods are constraining the reservoir capacity. Planning for all these strings used to be a very complicated process.

The presented approach integrates well performance, pressure support, and operating efficiency in order to optimize monthly production allowable. A workflow is embedded into an in-house developed tool, which ensures the correct approach to be applied and also increases work efficiency. The proposed approach enables a proper determination of technical rate for each string with respecting well performance and reservoir management limitations. Automated quality assurance is implemented through the process to avoid human errors due to the heavy number of strings. Efficient Voidage Replacement Ratio (EVRR) on both reservoir and segment levels has been applied to assure proper pressure support. EVRR only takes into account the effective water support from the peripheral water injection. Planned and actual production losses are both included for tracking the production efficiency.

The tool simplifies the process. The application of the tool has significantly reduced the working load and increased the accuracy of monthly production allowable. Well performance of each string has been highly respected in order to maximize oil recovery in a long term perspective. Pressure support on both reservoir and segment level has been achieved on a monthly basis. Besides, the tracking and comparison of the production efficiency could identify the unplanned production losses, as well as the potential production gains by optimizing production and activities plans, for instance, aligning reservoir surveillance plans and maintenance shut downs.
Use of a Novel Coiled Tubing Real-Time Downhole Flow Measurement Tool to Evaluate Matrix Stimulation Treatment for the First Time Worldwide
Authors: Cedeño Ramiro , Thwaiqib Ibrahim , Ahmed Danish , Sa Rodrigo
Published: November 2017

This paper discusses the first worldwide use of a novel coiled tubing (CT) real-time downhole flow measurement tool to evaluate the effectiveness of a matrix stimulation intervention performed in a salt water disposal (SWD) well by comparing the acquired data with the injection profile obtained via a conventional production logging tool prior to the treatment.

When SWD wells show a decrease in injectivity, the operator’s preference is to conduct stimulation treatments or reperforate target intervals before deciding on a costly workover operation. The decision to intervene is often made based on injection profiling performed using production logging tools along with injectivity index calculations. This evaluation represents an additional expense that typically requires significant time and logistical coordination. Alternatively, a CT real-time downhole flow measurement tool can be used to conduct, in a single run, i) injection profiling, enabling optimization of ii) treatment execution, before iii) conducting post-stimulation injection profiling to evaluate the effectiveness of treatment.

With the recent introduction of the CT real-time downhole flow measurement tool to facilitate the optimization and evaluation of matrix stimulation treatments, new concerns arose as to whether an actual correlation existed between said tool and existing injection profiles obtained through conventional production logging tools. Until now, there have been no field data to compare both approaches. During a recent matrix stimulation treatment on a SWD well, it was decided to perform a correlation between the data acquired by both tools before the execution of the acid stimulation. The correlation between the injection profiling obtained via the CT real-time downhole flow measurement tool and the injection profile obtained via production logging tool was remarkably similar. Additionally, it was confirmed during the treatment that the data acquired by the CT real-time downhole flow measurement tool can be further used to optimize the stimulation treatment, before performing another injection profile after the stimulation. Surface and downhole parameters acquired during the treatment were also used to model the well performance via nodal analysis.

The paper shows the world’s first example of the correlation of the injection profile obtained by the CT real-time downhole flow tool to the injection profile obtained via a production logging tool. This paper sheds light on the benefits of monitoring downhole parameters during CT acid stimulations. It also highlights the added value brought by the CT real-time downhole flow measurement tool and how its output correlates to production logging tool data.
Understanding ESP Performance in Multiphase Flow Condition in SAGD Production Wells
Authors: Shang Song , Bustamante Nicolas Gomez
Published: November 2017

High-temperature electric submersible pumps (ESPs) have enabled operators to lower the well drawdown and achieve higher production rate in steam-assisted gravity drainage (SAGD) wells. While theoretically the SAGD process should deliver a single-phase producing stream to the ESP system when bottomhole pressures are reduced to near steam saturation pressures, steam flashing could occur which can result in ESP performance deterioration and wellbore flow regime instability. The essential questions being asked for ESP performance in such SAGD multiphase condition are to identify the boundary at which the ESP and well behavior changes from stable to unstable operations (when is it happening), to determine the effects on ESP deterioration (what are the effects), and to develop solutions to maximize well drawdown with improved well stability (how to manage it).

In this paper, authors will present a new approach to understand ESP multiphase challenges in SAGD operations by using detailed fluid characterization and hydraulic models. The analytical approach identifies phase boundaries (phase envelope), calculates gas-water vapor volume fraction (GWVF) and predicts flow regimes as a function of surface and downhole flowing measurements.

Authors used Soave-Redlich-Kwong for the equation of state (EOS) with the Peneloux volume shift option to compute compositional model and construct pressure-temperature phase diagram for SAGD producing bitumen-gas-water mixture. By coupling the compositional fluid model with a well hydraulic model, one can calculate GWVF and phase splits along the production path and therefore predict flow regimes both upstream and downstream of the ESP. One can also perform pump stage by stage calculations and analyze the pressure contributions as operational stability changes. ESP design and operational recommendations to improve operational stability based on calibrated well model will also be discussed and evaluated in this paper.
Shedding the First Light on the Shilaif Source Rock in the Syncline, Onshore Abu Dhabi, UAE
Authors: Dasgupta Suvodip , Raina Ishan , Povstyanova Magdalena , Laer Pierre Van , Baig Muhammad Zeeshan , Casson Neil , Marzooqi Hassan Al , Suwaidi Salama Jumaa , Ali Humair , Subbiah Surej Kumar , Mello Ashish D’
Published: November 2017

Objectives

Conventional oil from the prolific carbonate reservoirs of Abu Dhabi has been produced over half a century from different anticlinal structures. Now, the time is right to go back to where it all started- the source rock in the depths of the syncline. The first well in the syncline provided an opportunity to characterize the reservoir quality of Cretaceous Shilaif Formation and understand the potential of the unconventional source rock oil play in Abu Dhabi.

Methods

The carbonate source rocks of Abu Dhabi are very different from the unconventional source rocks in the rest of the world and require a unique approach. An integrated workflow combining log, core and surface measurements has been carried out to characterize the Shilaif formation in the syncline in the south-western part of Abu Dhabi. Every measurement has a distinctive value and helps reduce uncertainties about Reservoir Quality. A critical examination of different available technologies was carried out to examine and optimize the characterization program to understand and reduce all uncertainties about reservoir quality.

Results

The Shilaif source rock in this syncline to the south west of Abu Dhabi is a carbonate-rich organic mudstone, which distinguishes itself by lack of clay and vertical heterogeneity. It is a hybrid source rock with simultaneous presence of both organic and inorganic pores. The extensive core analysis program provided insights about porosity, permeability and saturation, which were used to validate the log interpretation. Higher thermal maturity and stronger compaction lead to different reservoir qualities than the ones previously recognized on the nearby shallower anticlinal structures. The reservoir quality of Shilaif in the syncline (levels of oil saturation, producible pore-sizes and permeability) exceed the pay criteria known to be required to produce economic volumes of oil in other basins around the world. Geomechanical characterization shows that the rock is extremely compact and requires careful planning with respect to proper completions and appropriate fracturing strategy for this play to be successful

Novel Information

This is the first well in the syncline, targeting the mature source rock of Shilaif, based on previously existing literature. This paper explains the interpretation methodology workflow, that integrates all the measurements and discuss for the first time about viability of Shilaif as an economic source rock oil play in UAE, focusing on the syncline.
Production Response to Supercritical CO2 Cyclic Injection SCCI and CO2 Sequestration Potential in a Tight Reservoir, China
Authors: Wei Bing , Zhang Xiang , Wu Runnan , Lu Laiming , Li Yibo , Pu Wanfen , Jin Fayang , Wang Chongyang
Published: November 2017

CO2 based gas injection techniques for enhanced oil recovery (EOR) coupled with offsetting greenhouse gas emissions have received significant attention. In this work, a tight geological reservoir in China was focused. To further unlock the reserves after a natural depletion, the technique of SCCI was therefore suggested. The interest of this paper was to study the production response of the tight reservoir to SCCI and CO2 sequestration efficiency during this process. As a result of CO2 dissolution, the viscosity of the crude oil was gradually reduced with CO2 molar fraction and then nearly plateaued from 35 mol%. For this given reservoir, the optimal depleting pressure to implement SCCI was 20.88 MPa, which corresponded to the highest ultimate oil recovery. Moreover, the oil recovery increased linearly with CO2 slug size due to the pressurizing effect and viscosity reduction, which thus led to 11% of incremental oil recovery after a natural depletion. However, the oil production rate was found to rapidly decline with the decrease of core pressure. Due to the limited gas diffusion, the oil recovery steeply dropped with the cycle number and only 0.5% of oil was produced at the third cycle, indicating the insufficiency of SCCI to further mobilize the oil in place. During the SCCI, more than 85% of the injected CO2 species have been retained in the tight porous media.