bluuebunny/crossref_metadata_2025 huggingface dataset:
Integrated Geo-Modeling and Ensemble History Matching of Complex Fractured Carbonate and Deep Offshore Turbidite Fields, Generation of Several Geologically Coherent Solutions Using Ensemble Methods
Authors: Abadpour Anahita , Adejare Moyosore , Chugunova Tatiana , Mathieu Helene , Haller Norman
Published: November 2018

History matching reservoir models has always been tedious as it involves many uncertain parameters and requires many trial and error iterations. Frequently the modifications introduced seem artificial and may destroy geological concepts, only one matched model is obtained and the forecast of such a model may quickly be invalidated by new data. Eventually imperfect models lead to imperfect decisions.

Assisted History matching with ensemble methods has received a lot of attention in the past decade. In this methodology with an ensemble of models the correlation between all uncertain model parameters and the selected production data is assessed and using this correlation the ensemble of the models are modified to reduce the difference between simulated and real historical data in an iterative manner.

Ensemble methods are recognized to perfectly perform on the continuous Gaussian parameters, but their application on discrete geological parameters like facies and rock types has been a challenge for several years. Different solutions proposed to tackle this issue showed the importance of integrated workflows and the implementation of an assisted history matching loop in close relationship with the geo-modeling tools.

After several years of research, an assisted history matching tool based on ensemble method has been developed in Total via the integrated platform of geo-modelling Sismage-CIG. This tool has been industrialized early 2016 with the first operational study performed on a giant gas field in the Middle-East.

Ensemble methods are known to be relatively insensitive to the size of the model, number of uncertain parameters to be handled, number of wells and the length of historical data, but the industrialization of the tool to operate on huge complex fields with very large number of the wells needed several rounds of code optimization using state of art algorithmic approaches.

This tool showed outstanding performance on several types of models such as turbiditic deep-offshore and complex fractured carbonate fields. The latest history matching study performed with this method on a Middle-East field modeled with a grid containing 20 million cells, around 200 wells and more than 25 years of production history, involved more than 130 million uncertain parameters in each realization.

The use of assisted history matching with ensemble methods allows not only to take into account cell by cell heterogeneities as uncertainty in a coherent manner but it also delivers an ensemble of hundred matched models which creates a huge opportunity for forecast and decision making process. Moreover all models fully respect the geological a priori knowledge and the duration of history matching study has been drastically reduced (weeks instead of months if not years) using much less manpower.
Managing Human Barriers through Operating Integrity Management
Authors: Balakrishnan Hemant Kumar
Published: November 2018

ADNOC Gas Processing, one of the world’s largest gas processing companies, operates 5 large sites (includes 26 processing trains and an NGL distillation complex at Ruwais) and manages 3000+ kilometre pipeline distribution network which has a capacity of 8 billion standard cubic feet of gas per day. Both the country’s electricity and water supplies are dependent on ADNOC Gas Processing’s continuous operation and the safety of people working on or near their assets is dependent on their safe operation.

The ADNOC Health Safety and Environment (HSE) Code of Practice (COP) requires that ADNOC Gas Processing implements a systematic approach to HSE which is consistent with the ADNOC HSE Management System. Therefore the ADNOC Gas Processing HSE Management Manual (HSEMM) serves as the ADNOC Gas Processing HSE Management System (HSEMS) and describes expectations in line with the ADNOC COP and provides an overview of how these expectations are met.

In addition to ADNOC CoP Requirements, Process Safety Expectations from ADNOC Gas Processing’s Process Safety Management Standard are included in the ADNOC Gas Processing HSE Management Manual (HSEMM).
Advanced ERD Lower Completions: Delivering Accelerated Production and Enhanced Performance
Authors: Clews Matthew , Beaman Daniel , Newton Daniel , Kofoed Curtis
Published: November 2018

This Extended Reach Drilling (ERD) field re-development predominantly from four artificial islands of a giant offshore field in the United Arab Emirates (UAE) requires in most cases extremely long laterals in order to reach the defined reservoir targets, by the field development team.

The giant offshore field can be effectively split in to two (2) geographical sections; East and West. The East portion of the field has been developed extensively and is considered to have good reservoir properties. The West portion of the field has much lower quality reservoir properties and requires an engineered lower completion liner in order to deliver the required well performance that will adequately produce and sweep the reservoir. The engineered liner along with the extremely long laterals means significant time is spent switching the well from reservoir drilling fluid (RDF) non-aqueous fluid (NAF) to an aqueous completion brine.

In order to reduce the amount of rig time spent on the displacement portion of the completion phase, technologies have been developed to provide a method of switching the well from RDF NAF drilling fluid to an aqueous completion brine, without the associated rig time of the current displacement method. This technique eliminates the use of a dedicated inner displacement string and allows for the displacement to be performed with the liner running string, saving on average five (5) days per well.

In this paper the authors will demonstrate the technology and system developed to perform this operation, as well as the qualification, testing, field installations and lessons learned that were required to take this solution from concept to successful performance improvement initiative.
Pioneering Rigless Perforating, Clean-Up Operation, Well Testing with MPLT and Bottom Hole Sampling in Remote Platform
Authors: Preveen Preveen Kumar , Adhi Adhi Naharindra , Shazana Shazana M , Mior Mior Yusni , Nurbaiti Nurbaiti Baharuddin
Published: November 2018

Optimization of mature fields in maximizing the hydrocarbon recovery has been a major concern for exploration and production companies including Malaysian oil companies. Field A was discovered as gas field in 1980. A minimum sized 4 slot remote wellhead jacket with no processing facilities and helideck was installed for the development of the field. Oil bearing reservoirs were encountered in two blocks at Zone 5 during the gas development drilling and was not part of the original PSC.

As part of commitment to Malaysian host authority after taking over the field from an Independent Oil Company, the Project Management Team (PMT) were required to submit the Project Field Development (PFD) for oil reservoir development. Thus, perforation, sampling, well testing and logging were planned at well 1 to obtain representative fluid sample for PVT analysis and flow assurance studies. Considering the current downturn in the industry, critical decisions were made to conduct this campaign without the assistance of a drilling or workover rig which led to challenging phase of planning and execution within limited time frame. Through further optimization, the campaign kick started with a stringent budget and selection of concept which eliminated the requirement of a rig in order to achieve the objective set. A conventional Well Testing package with independent power source, lifting capability, wax management and heat radiation control was selected in order to meet the objective with the full capability to conduct well clean up, Multi Rate Test, Memory Production Logging and bottom hole PVT sampling.

The strategy of execution had led to a successful campaign with no HSE issues and fast tracked the project delivery by minimizing operation duration up to 1 month which resulted in 49% of cost saving (compared to the total planned project cost). The objectives of testing the reservoirs and understand the flow behavior of stacked layers of sand were achieved with sufficient bottom hole samples collected for facilities studies and field development " Figure 1Map offshore Malaysia
Sand Containment in Deep Gas Fields
Authors: Al Kindi Osama Mohammed , Dobroskok Anastasia , Pande Shriram , Mahruqi Salha , Regan Timothy , Winchester Arlene , Lawati Basayir
Published: November 2018

In the central area of the Sultanate of Oman, gas and condensate from five different fields are processed through one gas production station which has been in operation for over 10 years. Despite the highly consolidated nature of these deep sandstone reservoirs, sand was observed in the inlet separators. This work will: Illustrate the methods used to identify the source of sand (field, well, and formation).Establish short, medium, and long term solutions.

A strategy was created to investigate the source of sand and the extent of damage inflicted on the facility. Mitigation measures in the form of short to long term solutions were also implemented, addressing issues arising both in the surface and subsurface. Monitoring included clamp-on sand detectors and Sonic MPLT with camera with mitigation work including modification of the inlet separator and desander installation upstream the inlet separator

Two fields were identified to be the potential source of sand, based on the clamp on sand detection campaign. One field has commingled production from three reservoirs and was later confirmed to be the true source of sand; the second field was identified to be producing frac proppant only. Different techniques were used to narrow down the sand producing reservoir by comparative study of the minerology of existing core and produced sand samples, sonic MPLT with camera, modeling of formation stress mechanics, and other means of WRM interventions. Results concluded that sand production was not limited to a single reservoir yet the deepest is the major contributer.

To maintain the integrity of the facility, both surface and subsurface mitigation measures were assesed.

Due to limitations in the existing well completions, surface solutions were preferred.. By evaluating the facility, it was decided to modify the design of the inlet separator to trap the sand and clean it out periodically. In addition, well flow rates were constrained to below the erosion critical velocity to avoid any loss of containment. Finally, an integrity test was conducted to the flowline and equipment (from wellhead to export line), to create a surveillance and maintenance strategy to prevent facility damage. In summary: Modern technologies including Sonic MPLT with Camera proved capable of identifying the formation responsible for sand production under the conditions of fluid clarity and flow condition (Turbulent.Deep, well consolidated sandstone reservoirs are capable of sand production due to depletion and or water production.The facility downstream was protected by means of a simple modification to the inlet separator, demonstrating a simple and unconventional solution.Sand management system usage enabled sand removal from the inlet separator water stream during production, preventing loss of production.
Integrated Geological Modeling for Higher Confidence Development Decisions, Sultanate of Oman
Authors: Lars Hendrik Bellmann
Published: November 2018

Thermal EOR projects are technically and economically challenging projects. Improving the geological understanding and implementing these geological concepts into the static model were key to increase the robustness of, not only the geological model but also of the dynamic simulation.

The initial believe was that fine grained and mm scale laminated sediments act as vertical baffles for the steam distribution. The fine grained sands were low in permeability and the lamination were further reducing the vertical permeability. Grain size had the main impact on permeability and grain size was correlated with V-shale. Then, V-shale was used as a proxy for grain size and was integrated into a V-shale base porosity-permeability transformation.

After modeling the baffles explicitly, it was shown that against the initial belief, the main control on fluid flow was not a patchy baffle distribution. Instead the reservoir was overall reduced in vertical permeability. A lager impact had the V-shale base poro-perm transform, predicting an order of magnitude permeability range for a given porosity. Reducing the impact of the facies also reduced overall the uncertainty and improved the predictive power of the models. This in turn, helped to take development decisions with much higher confidence.
Innovative Approach to Enhance Reservoir Sweeping Efficiency Using Open Hole Swellable Packers in Gas Injector to Isolate Undesired Reservoir Section in Carbonate Reservoir Field of Abu Dhabi, UAE
Authors: Soufi Abdulrahman , Prahawinarto Bambang , Abdussalam Fouad , M. Khan Asif , Ashour Samer , Baudot Pascal , ElBarbary Abdalla , Salama Sheirf
Published: November 2018

Gas Injector Well is part of the project to improve the pressure communication between peripheral gas injectors and nearby producers in the Northern Part of Unit G WAG Patterns. This well was injecting gas only to upper part of Unit G reservoir based on the PLT and TGT results. Based on the study using tracer chemical injection, this upper Unit G reservoir was found to be in connecting with another nearby different reservoir.

The initial plan was to re-horizontalize the well and place injector in the proper reservoir, later this was changed and revised to use this innovation technology by installing blank liner with isolating packer to isolate the upper part of Unit G reservoir and let the lower part of open-hole remained open and connected to the required layer of reservoir.

After extensive discussion with vendors and performing simulation runs, finally agreed to run this kind of swell packer. Vendor custom designed this kind of innovative packer at their USA facility and transported to ADNOC Onshore yard just before the execution phase. First run the swell packer on blank pipe and placed it at desired depth in the open hole, later run upper completions and sting into the top packer of lower completion.

This way, we were able to inject gas into the lower part of reservoir Unit-G only, whereas the upper part was remained isolated completely. Using this technique saved company additional 2 million and extra time for re-horizontalization.
Well Placement Assessment Using Sequence Stratigraphic Zonation in a Complex Carbonate Reservoir
Authors: Salahuddin Andi A. , Khan Karem A. , Al Ali Reem H. , Al Hammadi Khaled E.
Published: November 2018

The paper is continuation of our previous work published in the SPE-192896. This work illustrates horizontal well placement sensitivity analysis that was conducted on a complex Valanginian (Cretaceous) unsaturated oil carbonate reservoir with strong water drive. Existing producer wells are 80% horizontal and the remaining 20% are vertical to deviated producers. The production history is the approximately 20 years and currently a peripheral water injection is implemented, all injector wells are horizontals. The well placement is very challenging due to the presence of some thin high permeability streaks intervals with permeability value of up to 1 Darcy. Early water breakthrough encountered in the existing oil producers is a serious problem which results in lower recovery factor and costly lifting treatment. In addition, premature breakthrough would leave behind the potential oil accumulation. Therefore defining the optimum placement location of the producers is a crucial decision to be decided during well plan and field development.

In this paper we applied novel approach for stochastically modeling complex carbonate reservoir lithofacies and properties distribution using a pre-defined High Resolution Sequence Stratigraphy (HRSS) model subzonation. The key static geological elements that must be well defined are HRSS framework, lithofacies architecture, and field wide rock properties. In this study, we apply integrated geosciences, geostatistical, and flow simulations to assess options for well placement.

This new holistic approach has recently been successfully implemented in the studied field. The resulted geostatistical model was able to explain pressure depletion and production rate as shown in historical production data of the field. The resulting dynamic model will hence provide reliable production forecast and reservoirs development plan which will eventually allow accomplishing the mandate recovery target.

Flow simulation was used to analyze the performance of the well considering horizontal the well azimuth, well inclination, wells length, wells position relative to the sequence stratigraphic zonation, and well position relative to the water contact. In addition, multi-scenarios of well placement were created to see the impact on the oil rate, plateau, and water breakthrough time. Some producers in the studied reservoirs have been drilled using the multidiscipline study recommendation. Actual property and rate derived from the newly drilled wells displayed a very reasonable match to the expected property from the model.
Successful Installation of Tubing Patches to Restore Well Integrity Leads to Remarkable CAPEX Saving at Water Disposal Well WDW
Authors: Siddiqui Muhammad Ali , Hassan Syed Saadat , Mubasher Muhammad , Latif Saqib , Dar Usman Anjum
Published: November 2018

The objective of writing this success story is to demonstrate how technology, in particular low cost solutions, are key to economically sustain and secure production from mature fields. Tubing Patch technology has been successfully utilized in Pakistan for the first time to restore the well integrity and saved huge CAPEX by avoiding expensive rig workover.

Tubing-Annulus pressure suddenly increased in one of water disposal well (WDW). Annulus pressure varied directly with variations in Injection rates which were the clear evidence that tubing-annulus communication had been established and basic check ascertains that well had integrity issue. Being the only injector in area all production and processing of gas is majorly dependent on its injection reliability and integrity. After detailed in-house working it was decided to run diagnostic logging with spinner (quantitative) & temperature log (qualitative) to identify the leakage points precisely. All potential leakage paths (packer, tubing, tool joints) were considered while selecting the diagnostic techniques to have conclusive results. Based on diagnostic logging three leakage points were identified. Before proceeding for remedial measures to restore the well integrity, it was mandatory to check health of old carbon steel tubing string therefore it was planned to acquire corrosion log. Based on corrosion logging results, completion tubular was established in good condition which steered to install tubing patches best Techno-Economical solution across the leaks to restore well integrity instead of rig workover for re-completion.

Consequently, three tubing patches, were successfully applied using wireline in water disposal well and integrity of well was restored. C-Annulus was pressure tested even after six months of installation and no pressure drop was observed during this interval.
Downhole High-Power Laser Tools Development and Evolutions
Authors: Batarseh Sameeh , San Roman Alerigi Damian , Reece John , Othman Haitham
Published: November 2018

The objective of this work is to present the development and evolutions of different high-power laser tools and their subsurface applications. These tools provide innovative and non-damaging alternatives to current downhole conventional technologies. In the lab, the laser technology has been proven to improve the flow properties and communication between the wellbore and formation. To achieve this efficiently in the field it is necessary to develop different tool designs and configurations, manufacture prototypes, conduct extensive tests, and optimize each part before upscale for field operations.

The laser source is mounted in a coil tubing rig at the surface; the coil contains the optical fiber cable used to convey the energy to the downhole tool. The tool combines mechanical and optical components to transform, control, and direct the laser beam. The design and configuration of each tool assembly varies depending on the targeted application. For example, the perforation tool converts and splits the beam into several horizontal beams; whereas the drilling tool emits a straight beam with controlled size for deeper penetration. They also incorporate purging capabilities to circulate gas or fluid to clean the hole from the debris and carry the cuttings. The entire assembly must be made to fit in slim holes as small as four inches. And finally, ruggedized to operate in a complex environment with high pressure and temperature.

The technology improves reach and provides versatility in a compact and environmentally friendly manner. For example, it is a waterless technology when it is used for fracturing, and a non-explosive based perforation when it is used to perforate. The unique features of the technology enable a precise, controlled, and oriented delivery of energy in any direction, regardless of the reservoir stress orientation and magnitude. Thus, it enhances reach to produce from pay zones that are bypassed by current conventional technologies and practice. The motivation to search for alternative technologies is the advancement of technologies including high power lasers, also the need to enhance several applications in deeper wells in an environmentally friendly manner.
First Abu Dhabi 2D/3D Seismic Merge. Fast Track Approach For Seismic Data Integration at Regional Scale in Exploration Studies
Authors: Parra Humberto , Caeiro Maria Helena , Neves Fernando , Gomes Jorge
Published: November 2018

One of the main challenges in the execution of regional studies is the integration of large amounts of data coming from different sources and different disciplines. Even within the geophysical domain, integration of thousands of 2D seismic lines and dozens of 3D seismic volumes is a very demanding task. The aim of this paper is to provide a description on the use of fast track methodologies for the integration of 3D and 2D seismic data at country level for regional studies.

This approach relies on a pragmatic way of merging seismic, processing data as point sets instead of traces, providing the flexibility of handling seismic information inside the geomodelling and geostatistical domain, where a grid of points can be resampled, reoriented, and ultimately merged into any desired geometry and resolution. The technical challenges include different spatial sampling, grid orientations, frequency contents and event timings. A preconditioning step has been included in the workflow in order to homogenize the data into a common ground, addressing compatibility issues of the different vintages through amplitude scaling, noise reduction and frequency balancing.

Merging in a practical approach different 2D/3D seismic data sets into a single volume reduces drastically the amount of time spent in the data analysis and interpretation of geological features at regional scale. In this case of study, the workflow enables a feasible path for merging all seismic data acquired in Abu Dhabi over the past seven decades. The integrated volume helps geophysicists and geologists to carry out better seismic interpretations and perform proper structural analysis and prospect assessments. Finally, the seismic data has been integrated into a unique survey by interpolating the 2D and 3D seismic data to fill the gaps and generating a pseudo 3D survey at country scale. This regional scale single 3D seismic data allows better understanding of the geological and structural trends present in Abu Dhabi.

This innovative approach offers a major advantage for regional data integration, expediting subsequent stages of seismic interpretation and description of the geological features at large scale for exploration assessments, prospect generation and 3D reservoir characterization.
Opportunities for CO2 Utilization Other Than EOR
Authors: Singh Prachi , Geuzebroek Frank
Published: November 2018

The historical agreement on international climate change at COP21 in Paris in December 2015 by 196 nations has accelerated the efforts to lower impact on climate change. The agreement contains the ambitious long-term global goal to limit global warming to "well below 2°C above pre-industrial levels and to pursue efforts to limit the temperature increase to 1.5°C". The International Energy Agency (IEA) has clearly stated that limiting global temperature rise to 2°C will require the energy sector to deploy carbon capture and storage (CCS). Hence, CO2 capture and suitable CO2 utilization option should be explored.
Proactive Application of Human Performance Science in Risk Assessment Process within Dynamic Operations of an Oilfield Service Provider
Authors: Yasseen Abdelsalam , Peresypkin Sergey
Published: November 2018

Human performance principles, which are well developed in aviation and healthcare, still represent an emerging science within the oil and gas industry. The industry managed to significantly reduce injuries over the last decade with multiple programs ranging from HSE Leadership to Behavior-Based Safety to the point when the incidents plateaued according to IOGP and IADC incident statistics. This triggered a deeper look into human performance best practices and their applicability within the oil and gas sector. This paper aims to provide an alternative approach to adopt Human Performance science to the dynamic operations risk assessment process within an Oilfield Services Company. After the analysis of the existing human reliability assessment tools, a decision was made to adopt a human performance tool known as Human Error Assessment & Reduction Technique (HEART) into a service provider’s risk assessment process with a primary focus on Error Producing Conditions (EPC). An internal survey was undertaken to define Error Producint Condition, which are most relevant to the dynamic nature of oil and gas services operations and couple them with the Reasons’s performance modes and their effect on error appearance. This approach allowed to significantly simplify the risk assessment process and adequately focus on key factors known to produce conditions for human error. This naturally integrated into our existing qualitative risk assessment to recalculate the overall risk of a certain task and enhanced workers’ ability to recognize potentially dangerous external and internal factors.

The field tests of the improved human performance risk assessments reshaped the standard risk assessment practices, moving the focus to and targeting the inherent unreliability of the task as a result of error producing conditions caused by unavoidable human interactions within the complex systems. This approach proved effective in improving the overall understanding of dynamic human reliability related risks among the front line employees by around 30%. The hypothesis is that by introducing key human performance factors to the day-to-day risk assessment will help build awareness of human factors and their relationship to the probability of an existing risk. At the same time, utilizing an already effective system – risk assessment – to introduce human factors methods will help avoid the complexity associated with its implementation of an additional human reliability tool and still get the benefit of key elements of a well-established method.

This approach has undertaken to combine two existing effective systems: a standard risk assessment with integrated human factors under a customized umbrella fully suitable for Oilfield Service Company’s work specifics. This paper provides insights on how human factors can impact the level of risk and outlines the control measures targeted at such factors that can be missed if a standard risk assessment is applied.
Integrated 3D Static Modeling of a Complex Carbonate Upper Shuaiba Reservoir, Block 9, Oman North
Authors: Al Hadhrami Fahad , Maili Eduard , Al Araimi Ahmed
Published: November 2018

The field was discovered in 1992. It produces oil and associated gas from two reservoir sub units of the Upper Shuaiba USh3F1 and USh3F2, and exhibits both structural and startighraphical traps. The reservoir units are compartmentalized by NW-trending normal faults into five fault blocks within the same field towards the North East. They are vertically separated by non-reservoir low permeability mudstone facies. US3F2 is setting above Orbitolina shale. The objective is to build a new geological model in a very complex carbonate reservoir, to allow for better reservoir development, and adding new field opportunities using state of art seismic data.

Lower unit (US3F2) consists of an aggradational sequence skeletal peloid-foram packstone/wackestone, and in-situ rudist-algal boundstone/packstone build-ups, which is localized to the NE-trending axis of the field. These sequences are deposited in a low to moderate energy environment. US3F2 reaches a maximum thickness of 50 ft in the rudist build-ups, but the width of the rudist-algal boundstone facies parallel to depositional dip (SE) is only 0.5–0.7 km. Cores exhibit abundant secondary porosity with an average of 30% and permeability up to 700 mD suggesting early subaerial exposure and leaching.

Upper unit (US3F1) is either absent or very thin across the crest and thickens to over 20 ft basinward; downdip, it is separated from US3F2 by a shale unit. US3F1 consists of an upward-shallowing deposits of Orbitolina mudstone, reworked stromatoporoid-rudist floatstone, small rudist floatstone, and fine skeletal grain-dominated packstone with rudist fragments.

3D model was generated covering large area of about 15x9km of the field. The new seismic horizon and faults interpretation were used in the 3D structural modeling. Cores descriptions and photos were used to define core facies, depositional environments and vuggy intervals. Rudist buildups direction of progradation was also defined based on BHI.

Reservoir rock Fabric number (RFN) was defined based on Lucia method and populated using veriogram per zone for the vertical wells using moving average method followed by Gaussian Random simulation, co-kriged with the moving average properties as a trend, for both vertical and horizontal wells. Porosity was populated with the same method. Water saturation and permeability were calculated using Lucia height function method.

Understanding of the reservoir heterogeneity, architecture and 3D modeling using RFN based on Lucia method allowed a better distribution of reservoir properties to be used in dynamic simulation for better history match, predict waterflood performance and adding new development areas.
Benchmarking Recovery Factors for Carbonate Reservoirs: Key Challenges and Main Findings from Middle Eastern Fields
Authors: Gomes Jorge , Narayanan Ram , Parra Humberto , Saputelli Luigi , Bansal Yogesh
Published: November 2018

The objective of this paper is to discuss the process of reservoir/field data aggregation, verification and validation process, to extract some key determinant reservoir parameters to be used in recovery factor (RF) benchmarking against global analogs. The subsequent step is to perform the benchmark of the reservoir performance against fields with similar reservoir characteristics and field development plans (FDPs), using digital databases and analytic tools. The use of data mining and analytics is also attempted to estimate RFs for undeveloped reservoirs.

RF improvement is the ultimate goal of any field development project being managed by National Oil Companies (NOC) or International Oil Companies (IOC). The extent to which the recovery of hydrocarbon resources is achieved, depends on our knowledge of the reservoir complexity (rock and fluid system), the field development strategy and the economic parameters. Each reservoir is unique in its characteristics and thus the need for the implementation of an appropriate field development scheme to maximize the recovery. One of the main objectives of this work was to identify a process that can assess the RF from a given reservoir while comparing it against a mature analogue across the globe, and then identify development opportunites that can further improve RF. To do this we need to 1)-classify ADNOC’s reservoirs in a systematic and consistent manner, 2)-extract key determinant parameters that contribute to RF and 3)-compare them with performance of similar fields extracted from worldwide databases. Once this is done and, with the assistance of digital databases and analytical tools, the benchmark can be performed.

This paper addresses all the challenges involved in the database preparation, data verification and validation process and presents a summary of the main findings in establishing the key determinant parameters used for the final reservoir classification (reservoir complexity index), which is used to select similar reservoirs for the recovery factor benchmark process. The paper exhibits also examples of RFs benchmarks for different carbonate reservoir complexities and architectures including but not limited to: 1)-reservoirs in transition zones, 2)-reservoirs affected by karstification and fracturation. 3)-reservoirs formed in complex clinoform (prograding) systems, 4)-reservoirs formed in aggradational layer-cake systems and 5)-reservoirs from sub-tidal sabkha environments with inter-bedded anhydritic layers.

The novelty of this work is the judicious integration of all static and dynamic data, the proper parameterization of key determinant reservoir parameters, statistics extracted from 3D geostatistical models, the use of predictive analytic tools including self-clustering and classification and dimensionality reduction to estimate RFs for undeveloped reservoirs with similar reservoir complexity.
Permian Basin’s Evolution of Hydraulic Fracturing Techniques Over the Last Decade: Vertical to Horizontal Wells
Authors: Uddin Saif , Cox Jim , Uddin Nasir , Uddin Raheel
Published: November 2018

Hydraulic fracturing has evolved at a rapid pace over the last decade, Permian Basin being the center of all the evolution. In 2011, vertical wells were completed on a day-time operations model with 10 to 13 different frac stages with different volumes of proppants and complex fluid systems. The same engineering & consulting teams in 2013 were challenged with horizontal wells to be completed using cost effective slickwater designs with high volumes of water and proppant on a 24-hour operations model. Finally, in 2018, Operational excellence with engineering accuracy has been possible due to lot of tweaking. This paper would present the successful completion strategies that have been put together from the lessons learnt over 5000 frac stages done in the field.

The difference between success and failure is often times determined in the way we rig-up even before the well head is open. Customer’s desire in total clean fluid pumped per stage or total proppant placement efficiency or both. Moving between fluids, slick water systems to linear and cross link fluids is very important to our success. Higher rates with slick water frac-jobs giving us high penetration using low viscosity fluids and the "sand banks" formed in the lower parts of the zone are swept using linear or dirty gel sweeps. Towards the end when there is no width available for the fractures we switch to cross-link fluids that provide more near wellbore conductivity with less penetration and, using high viscosity fluids and resulted in a perfect support system. Application of both the frac-theories on real-time changes was possible with the Men & Machine integration in the Permian basin.

The key characteristics of the Hybrid frac-jobs are:Usage of 100 or 40/70 mesh sand helped in fluid loss that also acts as a micro fracture proppant;Spear-heading with 2 batches of acids helped in breaking the zone and cleaning the perforationsDual Slickwater Pads with a pro-slug helped to get the penetration that we needed and also helps in determining the concentrations of the proppant behind the pad. This reduces our chances of screening out.Transition from 30/50 proppant to 20/40 proppant concentration based on the way the zone reacts to the proppant.Use of linear gel spacers allowed for higher sand concentrations in the Slickwater section of the frac-job. This provided us the width necessary.Tail ending with a 20/40 proppant using cross-linked fluids gave us a higher near wellbore conductivity

This paper gives a complete outlook to field application of Hydraulic fracturing and the special use of diverters from the lessons learnt in the Permian basin.
Flow Assurance and Improved Pipeline Efficiency Through Use of Low Surface Roughness Treatment
Authors: Nakatsuka Matthew , Veedu Vinod , Brown Erika , Thapa Sumil , Arumugam Ganesh
Published: November 2018

It is well understood that deposits such as corrosion and scale can greatly reduce the flow efficiency and throughput of a transport pipeline system. Regular intervention activities to promote flow assurance such as frequent mechanical pigging, introduction of chemical corrosion inhibitors, and introduction of drag reducing agents all require consistent operational expense, or significant pipeline downtime. Use of interior pipeline coatings and liners are potential long-term solutions which would represent a way to provide long-term refurbishment benefits.

This work describes a novel material designed to interact specifically with highly corroded and weathered pipe, enabling in-place application and refurbishment. The material is applied extremely thinly on the pipeline interior, such that it might be considered a surface treatment, yet it is designed for permanence and for strong adhesion to even severely corroded surfaces. This water-and-oil compatible, chemically resistant material shows extreme resistance to corrosion, particle abrasion and delamination under operational conditions, and is specifically designed to reduce surface roughness by several orders of magnitude. By reducing surface roughness, losses due to frictional drag can be minimized, together with the chance of forming deposits of iron scale and black powder that can constrict pipeline flow and overall production.

A case study is presented in this work which describes application of the coating to a fluid transport system, including a variety of different "challenge" features including: 90° 1.5D bends, valves, weld seams, flanged connections, and heavily corroded surfaces. The pipeline systems were all treated via an in-situ methodology and evaluated for flow performance both through modeling and experimental observation. The study of the practical effects of utilizing a low surface energy, low surface roughness coating that can be effectively applied to severely corroded pipelines with a minimum of surface preparation demonstrates how new material breakthroughs can allow for revitalization of previously mature intervention techniques.
Newly Designed Flow Activated Pulsation Tool for Coiled Tubing Deployed Matrix Acidizing Stimulation Applications in Extended Reach Carbonate Reservoirs
Authors: Saiood Hussain , Duthie Laurie , Shaheen Saud , Albaqshi Ahmed , Ali Moumien
Published: November 2018

Matrix acid stimulation throughout a well’s life cycle is a common technique applied to wells with impaired productivity. Coiled tubing is often chosen as the conveyance means for delivering the acid treatment in horizontal wells to the damaged zones and in applying effective chemical divergent for highly permeable zones. Due to the nature of helical buckling, weight stacking, and wellbore geometry, the coiled tubing operation is often limited in its ability to reach total depth (TD).

In short horizontal wells with slight reservoir contact, conventional methods are used to overcome the effect of drag and friction on the CT; such methods include pumping lubricant fluid. In more challenging applications and extended reach wells (ERW’s), a downhole pulsation tool is placed in the bottomhole assembly to add some axial vibration to the string and exert a pulling force to delay the onset of CT helical buckling, which, in turn, increases the reach of the coil. The significant reduction in friction is caused by the Flow Activated Pulsation Tool (FAPT), which allows the CT to increase its coverage and reach the desired target depth.

A new FAPT generation was developed by designing a new valve section to meet the objective of extending the CT reach in highly restricted (2.44") ERW’s. The development of the new valve section was completed after series of testing different valve sections to determine the optimum generated pulses that would increase the overall pull force at the lowest activation flow rate. The newly developed tool offers a stronger and higher performing pulses at lower activation flow rate, allowing it to operate effectively in more challenging ERW’s.

The FAPT development and the results of using the new tool after the first two global trial runs. The two wells were drilled as oil producing horizontal wells with +18,000 feet to TD. The wells were completed as open hole with electric submersible pumps (ESP’s) and a 2.44’’ restriction to allow well intervention. In both runs, the goal was achieved by reaching TD of the openhole section with effective placement of the acid treatments.
Reservoir Simulation of Planar and Non-Planar Fractures in Compositional Two-Phase Flow
Authors: Zidane Ali , Firoozabadi Abbas
Published: November 2018

In this work we present a higher-order numerical model for two-phase compositional flow in fractured media in 2D and in 3D unstructured gridding. Both planar and non-planar fractures are accommodated. All commonly used types of finite elements are covered in our model; in particular, quadrangular and triangular elements in 2D, and hexahedra, prisms and tetrahedra elements in 3D.

The fracture cross-flow equilibrium (FCFE) concept is adopted to model flow in the fractures. The hybridized mixed finite element (MFE) and the higher-order discontinuous Galerkin (DG) method are used to solve for the flow and the transport equations respectively. We have developed a computer-aided-design (CAD) interface connected to the mesh generator. Using this interface with the unstructured tetrahedra we can generate the most complicated fracture shapes. The complexity of fractures that we generate/simulate is not reported in the past to the best of our knowledge. Our model can simulate all range of fracture permeability values as opposed to other models where low permeable fractures affect the accuracy of the results. Efficiency and accuracy of our model are demonstrated in different examples in 2D and in 3D.
Well Abandonment Solutions Utilizing Bismuth and Thermite
Authors: Carragher Paul , Fulks Jeff
Published: November 2018

Well abandonment is often not thought of as a crucial part of a well’s life. As such, traditional methods of abandoning a well utilizing cement and bridge plugs are still common practice among most operators throughout the world. Although resins have been utilized by some as an alternative, there have not been anymajor new developments in well abandonment materials for nearly 100 years. Although each of these materials have their benefits, there are also limitations to their sealing capabilities. Bridge plugs lack a high expansion ratio required in some wells and rely on elastomers to seal, limiting their ability to seal in damaged tubing or open hole environments. Cement is porous and lacks the ability to block gasses from migrating through it. Resins must be squeezed into an area and can take days to fully cure before a seal is created. This paper will demonstrate a new way to create gas tight seals during well abandonment, overcoming the limitations of traditional methods and reducing the operator’s liability and potential environmental impact after decommissioning has been completed.
Experimental Investigation for the Effect of the Soaking Process on the Regain Permeability After Hydraulic Fracturing in Tight Sandstone and Shale Formations
Authors: Ibrahim Ahmed Farid , Nasr-El-Din Hisham
Published: November 2018

After hydraulically fracturing of shale gas wells, theoretical and experimental studies showed that over 75% of the injected water-based fracture fluids left unrecovered. The trapped water causes permeability damage and productivity impairment. The flowback water also tends to be highly saline, often with TDS contents of as much as 200,000 ppm. This study aims to investigate the effect of well shut-in before flowback stage (the soaking process) on the production of shale and tight sandstone formations.

Shale and sandstone samples were analyzed by X-ray diffraction (XRD). Marcellus shale and Kentucky sandstone cores were used. A modified core flood setup was used to allow porosity measurements by gas expansion method, then pulse decay permeability measurements, and fluid injection during the leak-off process. Nitrogen was used for gas expansion and permeability measurements, while 5 wt% KCl brine was used as representative of leak-off fracturing fluid. The fracturing fluid was injected under a constant pressure gradient (300 in the case of sandstone cores and 1,500 psi in the case of shale cores. After removing the pressure gradient, gas permeability was measured at different soaking times. Computed tomography (CT) was used to scan the cores during the experiment to observe the propagation of fracturing fluid in the core with time.

The results show increasing the regain permeability for sandstone formation was 60% of its initial value directly after the leak-off stage. Then, the regain permeability decreased with increasing the soaking time 38% of its initial value after the core completely invaded with leak-off fluid. The regain permeability was then increased with longer soaking time, as a result of reducing the chocking effect at the core inlet. The propagation rate of water saturation front from CT-scan data decreased with time until reaching the core outlet. The regain permeability on shale cores was 0.14 of its initial value and decreased with soaking time, due to depressed relative permeability curve on this tight pore-space cores.

This study addresses the mechanism of production enhancement or reduction as a result of the soaking process for shale and tight sandstone formations.
Advanced Reinforced Polymer Composite Coatings Revolutionize Corrosion and Wear Protection, and Offer Energy Savings in the Oil and Gas Industry
Authors: Borisov Rumen , Lenehan Paul , Wilson Nick
Published: November 2018

Corrosion, erosion, abrasion and chemical attack of process equipment is a challenge that costs the Oil and gas industry billions per year. Although corrosion/wear/chemical resistant coatings are commonly in use today, enhanced performance requires improved polymer coating materials and coating methods. In the past 20 years coating technology has come far in terms of material development and also in terms of documenting real results. The objective of this paper is to outline the advances and benefits of composite coatings in the oil and gas industry. Facing the challenge to replace expensive materials and technologies with the use of composites delivers to the Oil&Gas industries savings measured by the duration of the protection, saved time for replacement and use of non expensive materials as a substrate. This can be achieved with the use of technology that provides faster and repairable methods of surface treatment and adding the value of improved equipment efficiency.