The limitations of oil recovery from carbonate reservoirs are fractures and oil-wet conditions. To overcome the reservoir heterogeneities and reduce fracture transmissibility, preformed particle gel was applied in injector wells. Experimentally, low salinity waterflooding was applied to change the core wettability from oil-wet to water wet for enhanced oil recovery. However, both processes have limitations that cannot be resolved using a single method. A non-uniform fracture width and uniform fracture width models were built using carbonate cores to evaluate the coupling low salinity waterflooding and preformed particle gel in fractured cores and how could be used to improve in-depth water diversion treatment. The results showed that low salinity waterflooding improved in-depth water diversion when injected after PPG directly while seawater showed less effect than low salinity waterflooding. Also, the uniformity of fracture had a significant effect on plugging efficiency oil recovery factor from fractured reservoirs.

SAGD (steam assisted gravity drainage) has been proven as an effective technology to enhance heavy oil/bitumen recovery. The main shortcoming of this method is its inefficiency, a result of high water and energy consumption. As a solution to SAGD efficiency improvement, we propose the addition of chemicals resulting in higher recovery and reduced steam consumption. The objective of this paper is to screen new generation chemicals as additives and study the mechanisms and optimum injection strategies. This screening was achieved through Hele-Shaw type macroscopic visual experiments. We previously screened a wide variety of chemical additives ( Bruns and Babadagli 2017 , 2018 ) for steam flooding. As a continuation of this work, these chemicals were tested for SAGD conditions using a new visual experimental design where the optimal injection strategies were identified, eventually providing a reference for the selection of chemical additives for field applications. 11 conventional and new generation chemical additives (heptane, biodiesel, DME, LTS-18, Tween 80, Span 80, Novelfroth 190, ionic liquid (BMMMIM BF 4 ), silicon dioxide nanoparticle, DES9, and DES11) were selected based on both their strong thermal stability and enhanced oil recovery capability. The recovery improvement mechanisms for the different chemical additives and different injection strategies were identified through flow characteristics, emulsifying ability, viscosity reduction capability, and wettability alteration. Simultaneously, the mechanisms were studied from a macro perspective via analyzing areal sweep efficiency and microscopic oil displacement efficiency together with observing the images acquired during the process. Three different injection strategies were applied for each chemical: (1) chemicals were injected at the beginning, (2) in the middle, and (3) at the end of the steam injection. The chemical additives played different roles in recovery improvement, and different chemical addition strategies yielded different mechanisms. Heptane exhibited extraordinary characteristics with maximum "steam saving" (34.52%) when the middle injection strategy was applied and maximum ultimate oil recovery (64.75%) was obtained for the end injection strategy due to the ability to reduce the viscosity of heavy oil by dissolving around the chamber edge. Steamflooding with Novelfroth 190 showed an excellent performance for the middle and end injection strategies due to its ability to develop rapid oil drainage "channels". The addition of surfactant LST-18 presented the ability to improve the EOR by forming emulsions. Additionally, the distributions of the steam chamber in the Hele-Shaw cell were different due to the changed flow characteristics when the same chemical additive was injected at different times, thus showing the ability to reduce viscosity and form emulsions with different strengths.

In-situ combustion (ISC) is a promising thermal enhanced oil recovery (EOR) method for heavy oils. However, its field application is still limited due to difficulty in ignition, low combustion efficiency, unstable combustion front, etc. To improve the success rate of ISC process, we investigated the effectiveness of copper-based oil soluble catalyst for catalyzing combustion and in-situ upgrading of heavy oils. High-pressure differential scanning calorimetry (HP-DSC) and TGA were used to investigate the effect of catalyst on the thermochemistry (onset temperature, temperature range of reaction interval, heat effect, etc.) and kinetic parameters of combustion process. A Porous medium thermo-effect cell (PMTEC) was designed to study the catalytic combustion of heavy oil in porous media under air flow. And, a visual combustion tube (VCT) was developed to study the catalytic effect of catalyst on the ISC process, including improving combustion front propagation, in-situ upgrading of heavy oils, and oil recovery. HP-DSC results showed that copper-based oil soluble catalyst significantly shifted the low-temperature oxidation (LTO), transition stage (FD), and high-temperature oxidation (HTO) into lower temperature ranges. Especially for HTO, the end temperature was decreased about 120 °C. It was finished at a narrower temperature region with a higher heat flow, which implies that the combustion efficiency of HTO was greatly improved. TG-DTG data also showed the combustion reaction was transferred into lower temperatures. In addition, from TG-DTG and kinetic data, it can be concluded that the catalyst significantly reduced the activation energy in FD and HTO stage, which thus decreases the reaction barriers between FD and HTO and increases the continuity of reactions between FD and HTO. PEMTC experiments also showed that the ignition temperature of heavy oil combustion in porous media in airflow was decreased about 46 °C by copper-based catalyst. VCT experiments indicated that in the presence of copper-based oil soluble catalyst, combustion front propagate faster, oil recovery was 10% higher than without catalyst, and a deep in-situ oil upgrading was achieved with a significant viscosity reduction (9 times lower) and increase of saturates content (especially alkanes with lower carbon number C 11 -C 17 ). All these results showed that copper-based oil soluble catalyst has a great potential in improving the efficiency of ISC process and in-situ oil upgrading. Its application can help to improve the success rate and wide application of ISC process for heavy oil recovery, which will promote the highly efficient development of heavy oil resources.

With maturing oil fields there is an increasing focus on improving the oil recovery factor and pushing the envelope toward a 70% target. This target is indeed very challenging and depends on a number of factors including enhanced oil recovery (EOR) methods, reservoir heterogeneities, displacement efficiency, and reservoir sweep. Other factors also play a role including vertical sweep due to flow behind the casing, well integrity issues, presence of conductive faults, or fractures. Proper surveillance performed to evaluate the injectant plume front, reservoir conformance, well connectivity, assessment of the integrity of wells, and other factors can be crucial for the success of the project and its future development. The paper discusses special downhole logging techniques including a set of conventional multiphase sensors alongside high precision temperature (HPT) and high-definition spectral noise logging (SNL-HD). It was run to provide complete assessment of the injection – production distribution and any associated well integrity issues that might impair the lateral sweep of injectants into the target layer. This will be done for an injector and producer pair near the wellbore area. The operation was carried out with a tool string that contained no mechanical parts and was not affected by downhole fluid properties. It was conducted under flowing and shut-in conditions to identify flow zones and check fracture signatures. It also provided multiphase fluid velocity profiles. The results of the survey allowed for in-depth assessment of borehole and behind casing flow, confirming lateral continuity, and provided an assessment of production-injection outside the pay zone. Results will allow for better well planning and anticipation of possible loss of well integrity that might impair production in the future. Combining the behind casing flow assessment with borehole multiphase flow distribution can be used for production optimization by sealing unwanted water contributing zones.

With the global increase in the demand for crude oil, the need to develop enhanced oil recovery techniques is crucial. These techniques must focus on how to displace greater volumes of trapped oil from within a given rock. Since carbonate reservoirs constitute over half of the world's oil reserves, research has recently shifted its focus on recovery techniques as they pertain to carbonate reservoirs. However, due to complex depositional textures and diagenetic processes, carbonate reservoirs are challenging in terms of recovery. In this study, a robust experimental core flooding setup is employed to assess the impact of wettability of tight carbonate rock in governing the effectiveness of surfactant flooding. A series of flooding experiments with well-defined boundary conditions were performed on the low porosity core plug samples of Indiana Limestone. The three core samples used in this study are referred to as FD3H, FD4H, and FD5H. The cores have an approximate dimension of 13 cm length and 3.8 cm in diameter. The porosity is in the range of 13-21% and the permeability is in the of 0.69 −2.17 mD. The core samples exhibited differing wetting characteristics: strongly oil-wet, moderately oil-wet and weakly oil-wet. Initially, the core samples were saturated with oil and then water flooding was conducted until irreducible saturation was achieved. Later, surfactant flooding was performed as a tertiary recovery technique. The experimental results demonstrate that the efficiency of surfactant flooding increases as the tight carbonate rock get more oil-wet. The strongly oil-wet core manifested highest oil recovery, whereas in the weakly oil-wet core the recovery efficiency as a result of surfactant flooding was least.

The unconventional Shale and Tight play concept has grown to dominate the North American energy landscape, now accounting for the vast majority of onshore activity levels. However, not all Shale or Tight reservoir plays are created equal and what works for one play/Formation may not work for another. How should you design your stimulation, where to begin, what parameters are most impactful and what are some of the large economic leavers that can either make your project successful, or potentially cause it to fail. The Duvernay is an Upper Devonian mudrock, with significant quartz, carbonate and total organic carbon content, making it an attractive Shale gas target. Total Organic Carbon (TOC) varies from 2-17 wt.% and porosity ranges from 3-8% (averaging approximately 5%). The Formation is approximately 2,800 – 3,800 meters deep in the project area and is approximately 35-60m thick. Importantly, the target is significantly overpressured, with nearly double normal hydrostatic reservoir pressure (15-21 Kpa/m gradient). The native permeability of the Duvernay Formation is extremely tight, measuring in the 70-150 nano Darcy range, thus the formation requires horizontal wells with multi stage hydraulic fracturing, to be economically productive. The natural fracture density of the formation partially explains how a rock with such low matrix permeability can be so prolific, background tectonic fracturing is significantly greater than most other low permeability reservoirs being exploited in North America. Fracture densities have been measured in core and image logs at up to 8 fractures per meter, with average open fracture density's approximating 1-2 per meter. These fractures are steeply dipping (75-85 degrees) and created during tectonic events, both open and healed/calcite filled fractures are present. While the presence of natural fractures aid in the productive stage of the well's life, it can complicate the stimulation design and challenge the placement of a wellbore treatment. During the initial planning stages of an unconventional hydraulic stimulation program, the first step is to examine what other operators in the play are already utilizing. Early due diligence into what design elements are successful and almost as important, not successful, can save significant amounts of capital early in the evolution of a project. An example of this within the Duvernay project were uncemented ball drop liner completion systems. Due to the high-pressure pumping requirements of the Duvernay (up to 90 Mpa), these systems were not able to adequately stimulate the reservoir and were prone to install and isolation challenges. Limited entry Plug and Perf design dominates the Canadian unconventional energy landscape, this is where Chevron Canada Limited and KUFPEC Canada ("The JV") began its journey. The next critical stimulation parameters to decide on are proppant and water intensities, these will govern the duration of the stimulation and are key economic drivers (proppant intensity is typically the most significant variable in terms of cost and well productivity). Other major inputs into the frac program center around cluster design; number of clusters to be treated as part of a single frac stage, the spacing between the clusters and the number and orientation of perforations within a cluster/stage are key parameters. The treatment pressure is usually dictated by the breakdown and fracture extension pressure inherent to the reservoir, where the target treatment rate is a selection made by the operator (typically 10-15 m3/min for most unconventional reservoirs). Stimulation fluid design also varies by play type, Slickwater designs are some of the most popular in use today with hybrids, reverse hybrids and high viscosity friction reducer (VFR), also used in various quantities across play types. Connected to the stimulation design, is the interwell spacing distance, usually the wider wells are spaced from one another, the higher the proppant intensity. The key premise of limited entry design assumes that all the clusters within a fracture stage are taking fluid and sand equally and thus, have equal fracture half lengths, this is not the case (concept known as cluster efficiency), more discussion on that topic to follow later in the manuscript.

The solar energy system has become lucrative solutions for housing, commercial, as well as industrial sectors. This work presents the analysis of the present status as well as the perspective of solar electricity majorly photovoltaic technology. The paper focuses put on current technologies, installations issues, and challenges, as well as future anticipations. Diverse attributes linked to the photovoltaic (PV) module costs, as well as supporting technologies and green buildings approach. This paper tends in addition to discuss the diverse available PV system units. This solar photovoltaics case study examines the threats and opportunities inherent in implementation in a novel organization too, which will base on the low price and effectiveness of solar technology in the oil and gas industry by creating, installing as well as maintaining accessories of solar units.

Of the total oil and gas supply, a significant share is transported through pipelines. Ultimately the level and quality of cleanness of pipelines greatly affect the transportation of oil and gas. Considering this, any obstacle in the pipelines will delay the transportation process and will consequently reduce the amount of oil and gas transported at a high cost. Remarkable issues that are related to black powders are the contamination of product, reduction in flow of oil and gas, and environmental hazards. The main objective of this paper is to gain familiarity with the phenomenon of black powder, and based on the analysis design and builds a magnetic Nanoscale filtration/sorption system for crude oil treatment. A magnetic separation system is used for removal of iron and heavy metals from crude oil. The prime function of the radial field magnetic separation system is the breaking-down of black powder particles to submicron levels in full flow. Moreover, the paper has studied the enhancement of nanoparticle technology by using the graphene nanoparticles to improve the separation efficiency of the magnetic separation system. The graphene nanoparticles have enhanced the magnetic separation system. The resistivity meter has been used to measure the resistance of the oil, before being contaminated with black powder and after, in each step of the experiment. It has been observed that higher resistance leads to lower values of black powder. The analysis suggests that one stage of magnetic separation is more efficient than two stages. Measurement shows that with one stage magnetic separation procedure, the resistance of the oil sample, with black powder, increased from 2157 kΩ to 2969 kΩ, before and after the magnetic separator. The separation of black powder has estimated by 22%, and the magnetite material decreased by 16 gm. However, the resistance of the oil sample, with graphene nanoparticles, increased from 1799 kΩ to 2661 kΩ, before and after the magnetic separator. The separation of black powder has estimated by 24%, the amount of the magnetite material decreased by 19.58 gm. The 2% increase in the efficiency of the system can be attributed to the use graphene nanoparticles.

A workflow-based approach was implemented to improve the efficiency of well-test validation processes and to enhance the reliability of well models. This approach is based on automated validation and management-by-exception rules in order to highlight problematic tests and to execute an engineering validation process for approving or rejecting well-test results. The well-test validation process is dynamically linked with the ADNOC corporate database to fetch the well-test results automatically in real time. The first-step validation is an automated process that compares well test data against user-defined surface parameters criteria and validates the calculated subsurface parameters. Next, engineering validations of problematic test results are performed to analyze parameter trend plots and to adjust outflow model parameters or subsurface parameters for acceptable well tests. Additionally, a repository of calibrated well models is available for asset utilization. The well-test validation process was implemented throughout a large asset with multiple fields encompassing different lift types, including natural flow, gas lift and ESP. Automatic validation and in-built management-by-exception methodology reduced the requirement for engineering analysis of well tests by 70%, in an asset which validates more than 700 well tests per month. The most significant result is the reliability of the calibrated well models in the implemented integrated asset operations model (IAOM) to support and improve scenario predictions for the business objectives such as field-capacity test predictions and gas-lift optimization. The results of field-capacity tests achieved 98.8% of the targeted production rate for a particular zone. The holistic two-step well-test validation process allowed the identification of actual failed well tests in achieving an optimized well testing KPI and focused well test planning. This engineering validation approach enhances the skills of the engineer thereby, optimizing available human resources. The new management-by-exception approach forms the backbone of all other workflows contained in the IAOM, and has helped assets track well performance over time.

Over the years, cybersecurity threats have grown significantly, and securing Operations Technology (OT) assets is one of the biggest challenges within the oil and gas industry today. Poor security policies could lead to unauthorized access to business-critical assets, confidential information leakage and result in business disruptions causing HSE, financial, and reputational impacts. This paper details how advanced and robust security policies shall mitigate cybersecurity risks and enable a smooth execution of Digital Oil Filed (DOF) projects and other complex O&G projects involving high convergence between IT & OT environments. The DOF projects include integration of Industrial Control System (ICS) network with corporate network at various levels, and this mandates consideration of multiple layers of security controls to implement a defense in depth strategy in order to secure ICS & Corporate infrastructure. It includes establishment of an integrated governance model that orchestrates the Cybersecurity Management System (CSMS) that encompasses IT & OT, define a secure architecture for ICS, lay enforcement zones to segregate ICS network from the Corporate/ Enterprise network by enabling strong firewalling/ intrusion monitoring policies, perform continuous monitoring and develop response capabilities to combat cyber-attacks/ intrusions. Additionally, the awareness level of the entire workforce should be escalated to ensure they are ‘cyber risk-aware’ and comprehend how crucial it is to incorporate ‘security sense’ at work. Since cyber-attack aimed at ICS environments heavily leverage physical security weaknesses to introduce a cyber-physical impact, it is quintessential to consider robust physical safeguards to protect marshalling rooms, control equipment, and the overall perimeter of facilities. The "security" factor for DOF primarily focuses on the availability of the systems, minimizing downtime risks which is of paramount importance for Oil & Gas business. This paper focuses on KOC's comprehensive approach to secure its critical assets within DOF which comprises people, process and technology components that contribute towards achieving KOC's business objectives.

Maintaining and sustaining reservoir performance and health is a priority that requires ongoing assurance activities that will maximize recovery up to industry best practices. An automated and integrated reservoir performance tool has been developed to provide high-level assurances at both the reservoir and asset level. The Reservoir Management Performance Index (RMPI) is a set of indices that can identify key performance issues involving several aspects of the reservoir'sdevelopment and operational plans. This tool identifies mitigating measures that require action, assures production sustainability, promotes a reservoir-focused organization, and standardizes the reservoir performance evaluation in an organization. RMPIprovides a high-level overview and a platform for all management and operation levels, where observing the same set of results can initiate collective decisions that improve reservoir management. Such a system was developed for a company to monitor and measure the performance against expected standards and forecasts for the large number of reservoirs in its portfolio. This tool measures multiple aspects of reservoir management grouped into four major categories: Energy Management, Forcasting Relaibility, Reserves Management and Operations. The tool is tailored to account for various aspects such as: stage of maturity of the reservoir, primary or secondary depletion stage, etc. Each category consists of multiple individual metrics that combine actual field data with targets/forecasts and use an algorithm to calculate a score. These scores are weighted and aggregated for an overall score in each category and an overall score for the asset/reservoir itself. Several aspects accounted for in the metrics include (but not limited to): pressure management, voidage replacement, water and gas management, production and injection performance, reserves promotion and replacement, current RF, EURF, drilling and workover efficiency, Well-Up time, etc.

This paper presents the study of the European Petroleum Refiners Association into various pathways to produce a low-carbon liquid fuel to reduce the greenhouse gas (GHG) intensity in European transport. The European Union has set climate goals targeting 80-95 % GHG emission reductions by 2050. There is a strong focus on reducing CO 2 emissions from transport fuels. Refining industry can effectively contribute by gradually transitioning to e.g . new feedstock's hence reducing product-related CO 2 emissions (in combination with more efficient vehicles); integration with chemicals; further increasing CO 2 efficiency in refineries and Green Hydrogen. The Concawe study explores these so-called Low-Carbon Pathways with the potential to reduce the CO 2 emissions associated with the production and the use refined oil products [ Concawe, 2018 ]. Options for CO 2 emission reduction in refining are e.g. energy efficiency, low carbon electricity and carbon-capture & storage (CCS) and carbon-capture & usage (CCU). CO 2 emissions savings up to 70 % towards 2050 could be possible. Other pathways explored for future refining are e.g. the use of green hydrogen and the impact of fuel quality and bio-feedstock into the refinery. The use of advanced biofuels will play a significant role in the reduction of greenhouse gas emissions in transport. This paper being a summary of the FuelsEurope Vision 2050 [ FuelsEurope, 2018 ] presents the latest results of the ongoing study by Concawe showing possible pathways and CO 2 reduction potential for EU refining, site-specific factors will determine individual refineries preferred routes to contribute. The principles are generally applicable to refineries in other parts of the world.

Sabiriyah Mauddud and Upper Burgan are two of the giant reservoirs in North Kuwait(NK) under active water flood since 2000. About 400 MBWPD of water is currently being injected to maintain the reservoir pressure & improve the production/recovery. A comprehensive workflow process was developed and implemented to understand the waterflood performance, pressure-production response trends and map the opportunities to encash the benefits in terms of quick oil gains. The paper discusses the best practices adopted to increase production from two of the water flooded reservoirs in NK. Sound workflow process was created by integrating the technical inputs under collaborative environment from subsurface & surface teams. Series of segment reviews are conducted to understand the connectivity between producers & injectors, duly integrating all surveillance data. Analytical diagnostic tools have been used to distinguish between the good water and bad water and improve the VRR & sweep. Live ESP data is monitored and tracked at intelligent field collaboration centre to decide about the actions for the wells requiring ESP upsizing, downsizing and VSD/choke optimization. Wells with running ESPs were identified for VSD & choke optimization, using rationalized technical criteria. Wells with failed ESPs are reviewed for smart replacements with water shut off/water flood conformance & ESP re-design. Simultaneous actions for the well model creation; running sensitivity and scheduling in the workover rig are taken up. ESP upsize, along with VSD installation/choke optimization, was implemented in number of wells with significant oil gain (about 11% enhancement within a short time frame). As a part of the process established, this activity has become a regular practice in NK. Such wells are under constant monitoring so that water injection actions in nearby injectors, if needed, could be taken up such as allowable management, arresting the declining trend etc. The benefit of mega water flood activities have been reaped in terms of production enhancement adhering to the best reservoir management practices. Quick understanding of the Water flood response and relignment of actions on the associated wells via rigless and rig workovers is the key to the success for significant ramp of the NK production within a short time window of 6-7 months. Several work flow processes established during the campaign are now deeply imbeded within NK asset.

Kuwait Oil Company is currently producing around 3.2 MMBOPD out of which the major share of 1.7MMBOPD is produced by South East Kuwait asset (SEK). SEK has 14 Gathering centers (GC) with an average of 100 flowing completion per GC. It has always been a challenge to test individual completion to get correct rate and other well test parameters not only to calculate the exact production potential of the GC but also to back allocate the rates to the reserves produced. Since long time the prevailing practice in SEK was to test individual wells in the GC using GC test separator and as well as testing wells by portable test units. The rates obtained from above two methods were used to be compared with the expected calculated rates based on PI calculations and other reservoir properties. The GC test is done by diverting the well manually to GC test separator which does not incur any additional cost to the company compared to portable test which done by service company hired by KOC well surveillance department with associated operational cost. The need of portable test were justified because the old GC test facilities occasionally were giving inaccurate results and the results were used to be rejected by Field development engineers resulting in a repeat test request of portable test. This was not only taking long time to get the correct data but also add extra operational cost component to the company. In 2014-15 it was proposed to upgrade the GC well test facilities with state of the art technology. The upgrade was completed in November15 and the GC test facilities became operationally available in Dec 15. In spite of initial difficulties and inaccuracies in the tests results the GC test units were finally accepted in Jan16 to be accurate for all the GC’s after satisfactory comparison between the portable and GC tests results. There has been a great cost saving by the above in operating expenditure (OPEX) of SEK well surveillance. The number of portable tests has been reduced to 200 from the earlier average number of 1400 plus per year resulting a direct saving of around USD 3.6 million

In 2012, the North Kuwait Field Development Group led a change in reservoir development strategy to increase oil production through a number of mechanisms, including a transition from vertical wells to horizontal wells to increase reservoir contact in alignment with reservoir management best practices. Over 340 horizontal and high angle wells were drilled and completed between 2012 and 2016, targeting four main reservoirs in North Kuwait. Adoption of operational and well design best practices and appropriate drilling and completion technologies improved the drilling efficiency and completion performance for horizontal wells, as average drilling times were reduced. The latter, in conjunction with improved water-flood management initiatives, helped increase oil production to recent production rate records above 750 MBOPD. Drilling data associated with horizontal wells drilled throughout the campaign was continuously reviewed. The Reservoir Competency Asymmetric Assessment® (RCAA®) 1 methodology was used to understand the key drivers to improve drilling performance. A multi-disciplined team identified the main opportunities with relation to horizontal well drilling and completions and geological operational practices, and technology gaps. The key performance drivers and changes required to improve horizontal well drilling and production performance were ranked based on rig time savings and oil production gains. The implementation of operational best practices, well placement techniques, engineering design changes, technology adoption, mentoring, and knowledge management, delivered significant improvement in drilling performance. Average well drilling times were reduced by over 40% within two years of the horizontal drilling campaign ( Figure 1 ). In Q4 2014, the rig fleet grew from eight rigs to 23 rigs, presenting a challenge to continue drilling improvements during this expansion. The rapid growth in rig fleet combined with drilling more challenging well targets drove average well drilling times up to 61 days per well. This upward trend was reversed by continually applying the RCAA® process and innovative drilling operations tracking technology across the bigger rig fleet. Average well drilling times were improved to 53 days per well at the end of 2016. Figure 1 North Kuwait Annual Project Cycle Drilling Performance and Rig Count for Horizontal Wells Drilling Efficiency Index ® (DEI ® ) is a drilling and completions performance metric used to benchmark and track operational efficiency of the existing rig fleet or well type. It is a KPI that reflects both reservoir management and drilling practices. At the end of 2016, the North Kuwait drilling rig fleet of 23 active rigs was operating at one of the highest DEI ® levels. The improvement in drilling and well placement efficiency increased the active well count and helped North Kuwait obtain record oil production. An estimated value of $4 billion associated to capex reduction and improved oil production was delivered to KOC. The forward five-year plan for North Kuwait requires over 100 wells be drilled annually. Initiatives to further reduce drilling days have been identified and presented to the organization.

Digital Oilfields worldwide have accomplished many value added benefits. This paper discusses the benefits realized after implementing DOF technology in Greater Burgan Field of Kuwait. It describes how oil production is being optimized and sustained consistently. It highlights the cost savings achieved and reduction in production losses based on numerous improvements in work processes. Inevitably the ease in production management has led KOC towards further expansion. Burgan DOF technology comprises of digital instruments and infrastructure installed on wells and production facility. Well data such as pressures, temperature, water cut, flowing status and choke size is transmitted in real time to the field operations center for continuous monitoring along with key facility data. The intelligent operations system at the main collaboration center has automated workflows and smart alarm managers to instantly detect and calculate losses from wells or facility issues. Engineers can quickly analyze and make decisions for swift remedial actions using intelligent dashboards providing options for production increase from wells with extra potential. Significant tangible and intangible DOF benefits are seen from the continuous efficient asset production management. Oil production is being sustained at target with minimum downtime due to highly advanced monitoring. Customized dashboards and intelligent alarms help in improved diagnostics such as changes in water cut, sudden stoppage of well flow, scaling and slugging indication in wells due to pressure fluctuations from header trips or breaching of facility constraints. Production optimization scenarios are run daily calculating facility and well potential. Smart automated workflows integrating real time data with well and network models calculate opportunities for restoring or adding production quickly through the recommended wellhead choke or facility header changes. Burgan DOF has made troubleshooting easy, enabled quick and effective decisions and facilitated implementation of corrective actions much faster. It has provided KOC substantial cost savings with respect to BOPD restored and great reduction in non-productive time. In 2015-2016 three million dollars worth of cost saving was realized through restoration of 60 MBOPD by digital monitoring alone. Production optimization workflows provided an additional increase of 9 MBOPD. DOF technology has reduced frequency of well site visits and improved HSE measures due to presence of H2S detectors and remote controlled smart chokes. State-of-the-art collaboration center provides a highly effective collaborative work environment between the stakeholders Production Operations, Field Development and Well Surveillance enabling seamless communication for quick actions. DOF technology benefits are now well recognized by KOC leadership with concerted efforts ongoing to expand it all over the Greater Burgan field while North Kuwait and West Kuwait fields are also keenly engaged in planning switching to DOF with some pilots already completed.

Numerous oil and gas reservoirs in Kuwait are suffering from H 2 S contaminations. The H 2 S concentrations in the affected reservoirs vary significantly from low ppm ranges up to 40%. The H 2 S concentration levels are related to the generation processes. The high H 2 S concentrations observed in the Lower Jurassic reservoirs can be related to the TSR process. The dominant H 2 S generation process in the Upper Jurassic and Lower Cretaceous reservoirs is the thermal cracking of the organic sulphur compounds (OSC) occurring in the Najmah and Sargjelu source rocks. The H 2 S contaminations observed in the Cretaceous reservoirs show indications of multiple H 2 S sources. The bulk of the H 2 S in these reservoirs is generated in situ by the BSR process. In some fields clear indications for H 2 S migrated from deeper horizons e.g. via faults are observed. H 2 S contaminations are also observed at the top site facilities at various stages of the production process. The source for those contaminations is only partly in the subsurface. In several cases a distinct increase of the H 2 S contaminations of the fluids on its way from the reservoir well to the processesing facilities is observed. New sampling and analytical technologies tailored to the H 2 S problematic have been developed, which support the selection of the appropriate mitigation or remediation strategy. The utilization of modern low cost DNA sequencing technologies for the analysis of the bacteria and archea species provide essential information for the design of appropriate chemical cocktails for the mitigation. Reservoir modeling and forecast technologies have been developed to predict the development of the H 2 S concentrations in a reservoir. However, for a reliable forecast - irrespective which modeling system or tool is applied - the understanding of the H 2 S generation process is essential. Furthermore good quality and reliable H 2 S measurements are mandatory for the history match. The mitigation and remediation of H 2 S is a major cost factor in the field development and operations. Field souring i.e. the increase of the H 2 S concentration during field life is the worst case scenario, which could cause major investments to assure field production. Not only the costs for the H 2 S treatment materials (e.g. biocides, nitrate) but also the investments in corrosion inhibitors, H 2 S resistant pipes, valves, filters, and the upgrade of the processing facilities have a large financial impact. Furthermore HSE related measures and required safety and monitoring systems are increasing substantially the operation costs. In view of KOC's ambitions to increase the oil production by 20% by 2020 and the subsequently expected increase of H 2 S production, a contry-wide coordination of the treatment concepts for the H 2 S could improve the efficiency of the mitigation operations and could potentially reduce the investments and operation costs related to the sour gas issue.

This paper discusses a new and general method of backup cutter layout to extend bit life without sacrificing rate of penetration and two field case studies. This method includes the following aspects: Ensuring backup cutters do not cut or only partially cut when their primary cutters experience little to no wear and when the depth of cut of the bit does not exceed an expected value. This aspect is enabled by allowing backup cutters to have a minimal critical depth of cut that is greater than the depth of cut of the primary cutters. Ensuring backup cutters act as major cutters when the primary cutters' wear depth is equal to or greater than the underexposure of the backup cutters. This aspect is enabled by allowing each backup cutter be rotationally behind its primary cutter by approximately 180° or greater. The underexposure of each backup cutter relative to its primary cutter is carefully calculated based on the primary cutter's wear and drilling slope.

Per recent analyses, in the near future, over half amount of the oil extracted globally will require some form of enhanced oil recovery (EOR) technique. Existing literature and historical investigations suggest that in oil reservoirs having viscosities between 10 — 150 m. Pa.s, there is a substantial prospective for tertiary recovery through the implementation of polymer flooding. For reservoir oil viscosities above 150 mPa.s, the polymer pumping efficiency goes down as polymer injectivity reduces significantly with increasing injection water viscosity that is used to attain a favorable mobility ratio at such high oil viscosities. To overcome this limiting factor, in this study, we propose the use of supramolecular assemblies (SMA) that have adjustable viscosity properties. Complex long-chain amino-amides and maleic acid are used to make these assemblies, which allow it to have reversible viscosity depending on the solution pH level. To maintain high injection efficiency, during pumping, SMA solutions will be kept at low viscosity values. On entry in deep reservoir or at oil contact phase, through introduction of an external stimulus, the viscosity of SMA solution will be reversed to a much higher viscosity. This will allow to sufficiently improve the mobility ratio. Preliminary results from lab-scale studies have indicated that along with reversibly adjustable viscosity property, SMA solutions are also tolerant to high temperatures and salt concentrations. Supramolecular solutions can be contemplated as remedy polymer systems, since unlike conventional polymers they disassemble and re-assemble when exposed to high temperature and stress conditions. In such conditions, conventional polymers generally undergo degradation. Additionally, through molecular scission processes SMA solutions can also be used in highly confining environments as well as in permafrost conditions and thin zones where conventional thermal techniques are not applicable. The objective of this work is the development of a novel SMA system that has the aforementioned properties of reversibly adjustable viscosity through pH, tolerance to high temperature and salt concentrations through desired interfacial properties. Lab-scale preliminary results have shown the potential economic benefits of the use of SMA solutions on a field-wide scale. Based on the results, it must be emphasized that SMA systems have a worldwide application in oil reservoirs for EOR purposes.

West Kuwait's 22-in. section comprises a vertical hole through 3,500 feet of interbedded carbonates varying significantly in compressive strength, and drilled commonly with minimal or no fluid returns. The section is typically drilled with roller-cone tungsten carbide insert (TCI) bits because large polycrystalline diamond compact (PDC) bits are extremely costly and require expensive performance motors to support their generated torque. PDC bits are also at risk of impact damage when drilling through the interbedded formations in this interval. Operators tend to apply higher drilling parameters while in the lower compressive strength intervals to achieve higher rates of penetration (ROP). Consequently, when the TCI bit enters the following harder formations with the same high operating parameters, it often suffers severe cutting structure damage. The result is reduced ROP. Greater weight on bit is then applied, causing further bit damage and possible sealed bearing failure. An engineering project was launched to develop a TCI bit specifically for the interbedded carbonates of this section. The primary challenges of the project were: Ensure the bit finishes the section in one run Improve dull condition of bit coming out of hole Surpass current field average ROP consistently Maintain efficient cleaning at lower flow rates for drilling in complete fluid-loss scenario Based on data and experience in drilling the application, an engineering process took place where several designs improvements with potential to improve performance were identified and trialled. Field engineers then worked onsite to identify how to drill the interval with optimal parameters for each sub-layer. The final design included: Specialized TCI cutting structure for carbonate drilling High impact-resistant insert geometry Simulated hydraulic efficiency to improve hole cleaning Improved high aspect ratio elastomer seals designed to endure longer runs Specialized tungsten carbide to improve cutting structure durability The engineering process yielded a design that successfully drills the complete section in one fast run - the fastest of the section - with an improved field average penetration rate to 63%, saving the operator more than 38% in associated cost for drilling the section. The application-engineered cutting structure enabled the use of lower drilling parameters than normal, thereby improving drilling efficiency and enhancing the post-drilling dull condition from the average of 3-3-BT to 1-2-WT. The paper shows a case study in Kuwait demonstrating the engineering and results of designing a TCI bit matched to application.