bluuebunny/crossref_metadata_2025 huggingface dataset:
A Novel Quantitative and Predictive Reservoir-Souring Approach to Assess Reservoir Souring During Planned-Waterflood Development Plan
Authors: Salimi Hamidreza , Namdar Zanganeh Maryam , McCarthy Sven , Pirlea Lucian , Balushi Haitham , Lawati Mustafa , Yarabi Mohamed
Published: November 2019

Souring potentials of fields during planned-waterflood development need to be investigated to enable the selection of the injection-water source and facility-design options. This paper presents the application of a novel reservoir-souring approach to assess the souring potential of a Middle-East field that is associated with three potential injection-water sources in terms of souring, to recommend ways to prevent or reduce H2S production, and to determine the optimum solution for injection water.

The novel approach includes fluid sampling and analysis, a desktop study, a dynamic-reservoir simulation, and a surface-facility evaluation. In the desktop study, a qualitative assessment of souring associated with the three potential injection-water sources (shallow-aquifer water, produced water, and mixtures of produced and shallow water) and mitigation strategies to limit future H2S concentrations were carried out. Subsequently, a compositional non-isothermal dynamic model that includes 3 phases, 18 components, and 18 reactions was developed to quantitatively predict the most-likely and the worst-case H2S levels over the field’s life. Several sensitivity runs were performed to assess the impact of the key uncertain parameters on the H2S level.

The results indicate that re-injection of produced water (deep aquifer) with a salinity of 173,000 mg/l not only has a very low souring risk, but also offers the most manageable conditions in terms of scaling and corrosion control for both the reservoir and the facilities. For this water, the simulated earliest H2S-breakthrough time is year 2038 and the H2S concentration in the gas phase will not exceed 1000 ppmv until 2074. On the other hand, injection of the shallow-aquifer water with a salinity of 11,000 mg/l has a high risk of souring. The simulated earliest H2S-breakthrough time is 2025 and after breakthrough within one year the gas-phase H2S concentration reaches 1,500 ppmv at ambient conditions. When mixtures of produced and shallow-aquifer water are used, the risk of souring depends on the mixture salinity; if it would be higher than 150,000 mg/l, the souring risk would still be very low, otherwise the souring risk would be moderate to high.

In terms of mitigations, nitrate injection is very effective in significantly reducing the high souring risk of injecting the shallow-aquifer water. Stripping out the dissolved H2S in the shallow-aquifer water can delay the H2S-breakthrough time by 11 years and can reduce the max H2S concentration by 50%.
Successful Evaluation of Tight Gas HPHT Carbonate Formation with Extremely High Sour Content and Elemental Sulphur Presence
Authors: Yugay Andrey , Ahmad Mubashir , Bankole Ibukun Olatunbosun , Alhouqani Shamsa Sulaiman , Al Qallabi Salah Al , Pimenta Gervasio
Published: November 2019

As a part of Country strategy to fulfill growing demand in gas energy in the country, development of Arab formations started. This paper shares the actual case history of successfully completed evaluation of Arab formation in one of the Company fields. High temperature (300F), high H2S concentrations (up to 37% H2S) and presence of elemental Sulphur dictated usage of very exotic downhole corrosion resistant alloy (CRA) material. Tightness of carbonate formation (less than 1 mD) pushed to drill 10,000’ horizontal section to meet project objectives. High reservoir pressure reaching 5,700 psi in combination with all conditions above resulted in high level of risk during initial project evaluation and required very robust HSE and Integrity systems in place with no chance to failure.

Arab formation evaluation project started in 2014 and was performed in several steps, with gradual increase of the complexity of the each next stage: from vertical well to horizontal, from sampling to longer duration testing, from carbon steel completion to fit-for-purpose inhibition and high grade CRA materials. Efficient collaboration among multidisciplinary teams, continuous management support and clear communication channels between all stakeholders proved to be a key to success for this challenging project. The project included involvement of high capacity rig to fulfill extended reach depth (ERD) well requirements, specific well intervention techniques while drilling and testing, usage of special inhibitor for high sour wells and finally inspection of the recovered completion. All Company available best practices and technical competencies applied in this project allowed to overcome all the challenges and achieve appreciable sustainable gas rates, meeting all set objectives with no HSE incidents and failures. Findings and lessons learned received are used to tailor next stage of the project to ensure most efficient scenario of field development to support country strategy in increasing energy potential.

The content of the paper gives a good understanding to the readers on the key aspects and main challenges that they may face during initial evaluation stage of the tight gas high pressure high temperature (HPHT) carbonate formations with high H2S content. The document could be used as a local considering current government strategy of massive attraction of new business partners for the exploration of new gas and gas condensate blocks in the region.
Holistic Approach to Prolong Giant Onshore Abu Dhabi Gas Field Production Plateau and Optimize CAPEX/OPEX Using an Integrated Asset Model as a Digital Twin
Authors: Latif Mohd Anwar , Bedewi Mahmoud , Abdullayev Azer , Al Saadi Noura , Saleem Babar Mohammed , Al Bairaq Ahmed Mohamed , Al Ameri Ammar Faqqas
Published: November 2019

A giant gas field consisting of six stacked carbonate reservoirs of Lower Cretaceous age with gas caps and non-associated gas where the production follows a depletion scheme is discussed. The field has a production history of more than 30 years with more than 150 gas condensate wells flowing to a common surface network, which means production decline is inevitable.

This study assesses various mitigation actions to extend the plateau or minimize the anticipated inevitable production decline, and optimize costs while adhering to a service level agreement (SLA) with the consumer gas plant.

This paper illustrates how the use of an integrated asset model (IAM) as a digital twin of the actual asset can help provide a holistic approach for evaluating critical investment decisions.

The proposed mitigation actions were mainly focused on surface facilities because gas fields are sensitive to backpressure; the mitigation actions were primarily geared toward reducing backpressure to remedy the anticipated production decline.

Gas plant inlet/outlet pressure reduction proved to provide significant plateau extension. This finding was verified by means of field trials. Intermittent and weak producers responded positively to the implementation of wellhead compression during the IAM simulation; consequently, a pilot was implemented in the field to verify the simulation conclusion. IAM also proved that adding 20 new infill wells would help accelerate gas production, if necessary; but, it requires further economic justification before implementation.

Simulating scenarios, such as the segregation of wells currently sharing flowlines, had a minor effect to overall field production. A previous reconfiguration of compressors within the compression stations proved beneficial in mitigating production decline and accelerating gas volume. However, because of operational risks and associated costs, future reconfigurations showed minimum impact.

A significant portion of the study was focused on modeling the downtime of various components of the asset surface facilities as per the integrated shutdown plan (ISDP) and identifying alternative routes to minimize overall gas production disruption and to adhere to the SLA commitment.

The focus on precisely simulating the operational side of the field was enabled by the use of IAM as a digital twin of the actual asset. In addition to the usual simulation benefits, such as the assessment of various sensitivities before implementing significant investments in real life, this holistic approach can help realize cost-saving opportunities and help ensure future adherence to the contracted gas rate.
Proactive Management of Occupational Health using Fatigue Risk Assessment
Authors: Kulkarni Poorva , Al Hammadi Saud , Al Zbeidi Osama , Al Marzooqi Meera
Published: November 2019

Company conducted a Fatigue Risk Assessment Study to estimate the fatigue levels of approximately 9000 shifts and the risk of incidents occurring due to operator fatigue.

The findings provided an insight into the likelihood of fatigue and risk of errors / incidents occurring for approximately 9000 shifts of control panel operators working on a 4×4, 12-hour, day and night shift pattern. The results presented in this paper are limited to the assessment conducted for day shifts in order to demonstrate the methodology.

The study compared different shift patterns in order to identify shifts with higher fatigue levels and identify control measures to reduce operators’ fatigue levels and risk of incidents occurring to As Low As Reasonably Practicable (ALARP).

Lowest fatigue and risk levels were identified for the current 4×4 shifts in comparison to 7×7 and 28×28 shift cycles followed by other Companies. In order, to lower the risk to as low as reasonably practicable (ALARP), additional control measures such as training, campaigns, ergonomic assessments, KPIs such as tracking incidents by fatigue levels, etc. are being rolled-out for implementation.

This is a novel approach on the combination of a qualitative (IOGP) and quantitative (UK HSE) fatigue risk assessment methodology that has widespread applicability, prospectively in terms of shift design and prevention of incidents caused by fatigue induced impairments and retrospectively for incident investigations.

This Fatigue Risk Assessment Study fosters proactive occupational health management by promoting health of employees and preventing / reducing fatigue and thus plays a vital role in the prevention of sickness absenteeism and illnesses associated with chronic fatigue.
Rigless Intervention to Secure Wells with Sustained Annulus Pressure and Tubing Integrity Issues Using Conformance Chemicals on an Unserviceable Platform
Authors: Tiong Yuang Yong , Leong Azemi , Azizan Yusri , Adizamri Rudzaifi , Amilin Khairul
Published: November 2019

An operator in offshore Brunei plans to abandon uneconomical wells that were completed during the 1980s. These wells have sustained annular pressure in the casing, some of which are close to the maximum-allowable annular casing pressure, and require immediate intervention to secure the wells. A rigless operation to isolate the pressure source is required to optimize future abandonment operations using a rig.

Typically, such operations include spotting the cement plug across the perforation using coiled tubing to isolate the pressure source. However, because six of the wells were located below an unserviceable helideck, coiled tubing intervention was not possible, leaving bullheading as the only viable option. The risk associated with bullheading includes the inability to access the end of the production tubing to set an additional mechanical barrier after the cementing operation because of the inability to circulate the well clean. Additional challenges included the unserviceable condition of the pipeline on the platform, which prevents flowback handling, and the lack of crane availability to conduct lifting operations. A small volume of porosity sealant polymer that is lower risk compared to cement slurry was selected to permanently shut off the zone. To overcome the surface limitations, an integrated intervention vessel operation was designed and equipped with fit-for-purpose pumping, flowback, and slickline packages.

After obtaining access to the formation through slickline, treatment was successfully pumped, and the formation sealed off effectively. The slickline mechanical plug was set in the tubing without issue, resulting in each of the wells being safely secured and an estimated 2 weeks of rig time saved for the final abandonment operations. The result marked the first successful operation to secure a well using a small volume of porosity sealant and demonstrated that a similar method and planning can be used to perform future intervention with similar surface conditions and constraints, safely and economically.

Conventional abandonment methods use a coiled tubing unit or rig for intervention. However, an unserviceable helideck restricted access to six of the wells and removing the helideck was not cost effective. This prevented the use of a coiled tubing unit or rig; therefore, bullheading was the only option. Fluid placement during bullheading operations is limited compared to coiled tubing. During the design stage, a small volume of porosity sealant fluid was selected because of the short perforation interval and tight formation.
Achieving Zero Flaring through Oil Tanks Gas Recovery: Case Study from Oman
Authors: Al Kalbani Haitham , Al Marhoobi Faheem , Al Siyabi Hamed , Al Shabibi Saleh , Al Kiyumi Amran
Published: November 2019

The intensity of global warming has increased in recent years and reduction of greenhouse gases become a necessity. The Paris Agreement's recently signed by 196 countries long-term goal is to mitigate the global average temperature to well below 2 °C above pre-industrial levels (Wikipedia, 2018); and to limit the increase to 1.5 °C, as this will results in controlling the risks and effects of climate change. Governments are going towards stringent regulations and implementation of carbon credits.

In oil and gas industry, gas is produced with oil and it is mostly treated and transported for various industrial uses. However, a significant portion of this gas is used in the facilities for power generation and other uses. Tanks for example, are usually blanketed by fuel gas. During the operation of the tanks gases are lost due flashing, level variation and thermal variation. The gases are usually collected in a header and then flared through atmospheric gas flares. The flaring will result in higher CO2 emission. Inefficient flares will also result in incomplete combustion of hydrocarbon and consequently the emission of methane and other gases.

Currently, there are various technologies used to recover the gas, compress it and reuse it. Ejector, Eductor or compressors are mainly used for such application. Depending on the available resources, utilities, operational and maintenance experience and the return on investment any of these technologies can be selected. Daleel Petroleum LLC, who are operating a field in Oman, set a target of zero flaring by initially installing a gas treatment and compression plant to recover associated gas which was successfully commissioned in 2018. The next step is to recover the gas from the tanks, compress it and send to the gas treatment plant for further processing.

This study covers Daleel petroleum LLC's approach in selecting the optimum technology for AP gas recovery and utilization. The study focused on setting the selection criteria and return on investment. A selection criteria will provide other operators with a holistic approach to take decision towards zero flaring and it will set a clear path on how to achieve it.
Completing Ultra Extended-Reach Wells: Overcoming the Torque and Drag Constraints of Brine
Authors: Morrison Alexandra , Serov Nikolay , Fahmy Ahmed
Published: November 2019

The use of invert emulsion drilling fluids as a key enabler to successfully drill extended reach wells and access hydrocarbons that were previously out of reach has been common practice across the industry for decades. One of the more recent, but less frequently discussed, topics is how to effectively design a solids-free, brine-based completion fluid to facilitate the running of the completion by reducing torque and drag.

The choice of lubricant for brine-based completion fluids is primarily driven by technical performance, both in terms of torque reduction and compatibility with the brine, potential brine contaminants, such as divalent ions, invert emulsion drilling fluid, and crude oil that may be encountered in the field.

During the planning phase for a recent ultra-extended-reach drilling campaign located offshore Sakhalin Island, it was highlighted that, without a lubricant in the completion brine, neither the upper nor the lower completion would be able to reach the required total depth, based on historical friction factor data. The brine planned for use as a completion fluid must demonstrate lubricity features near that of an invert-emulsion drilling fluid for the well to be completed successfully.

This paper summarizes the laboratory test results to validate the lubricant selection and provides details about the operational procedures and results achieved after using the new lubricant in the field for the first time.
Lessons Learned from Hydraulic Fracturing the Diyab Shale Gas Wells in UAE
Authors: WU Yang , Newby Warren
Published: November 2019

Since 1st February 2019 Total E&P UAE Unconventional Gas B.V started to operate the Diyab shale gas field in which three horizontal exploration wells had been drilled by ADNOC. Mult- stage hydraulic fracturing treatments were performed on these wells followed by long term well testing to assess the formation potential for a further development.

It was a challenging project since it was the first shale gas frac campaign in UAE where the unconventional reservoir developments are at beginning phase. Various operational problems emerged in wireline pump down, coiled tubing milling and H2S treatment operations, especially during execution in the first well. These operational issues were mainly related to equipment availability and compatibility, personnel competency, logistics support and societal concerns of environment. Corrective measures and innovative designs were conducted to solve the technical issues and improve the operation performance. Good learning curves of different operations were achieved from the first well to the third one.

The lessons learned from this hydraulic fracturing campaign are valuable experience that will be applied to the future pilot wells in Diyab field for the continuous optimization.
Hyper Digressive Screws – The Next Technological Step for Substantial Increase of Efficiency in Twin Screw Multiphase Pumping
Authors: Korte Eike Steffen , Blatt David Johannes , Lewerenz Jörg , Monnickhoff Jeroen Olde , Rohlfing Gerhard
Published: November 2019

Multiphase twin screw pumps are used for delivering gas-liquid-flows even at high gas rates and high differential pressures. In order to match the process conditions regarding pressure and flow the screws, the conveying elements of the pump, can be designed accordingly. The screws are forming enclosed chambers with the surrounding casing and the pitch of those screws is determining the chamber volume and hence the pump flow. To increase pump flow and efficiency digressive screws are known in the oil and gas industry. The next technological step are hyper digressive screws, which are used for the first time in pumps for a Canadian oilfield.
Modelling the Application of Advanced Completion Technology for Improving the Performance of Gas Injection Techniques in Unconventional Oil Reservoirs
Authors: Moradi Mojtaba , Konopczynski Michael , Smith Michael
Published: November 2019

The oil recovery efficiency of unconventional reserves is very low due to their micro-permeability formations and quick depletion of pore pressure near to the fractures and wellbore. Several enhanced oil recovery techniques have been suggested to increase production efficiency in these reservoirs. For example, injection of gas or carbon dioxide in fractured wells, and either producing oil from adjacent wells or back-producing the injected gas and reservoir fluids in the same wellbore after a suitable soaking period (huff & puff). The effective distribution of the injected gas in these wells and the ability to keep gas in the reservoir for maintaining energy and/or having longer contact with interstitial oil can greatly affect the recovery efficiency. This paper describes how the use of advanced completions utilizing passive inflow control devices (ICD) and autonomous inflow control devices (AICD) could significantly improve the performance of EOR process in unconventional oil wells.

ICDs can be installed to balance the distribution of gas injection among the fracture clusters in a horizontal well segmented into multiple compartments at the injection stage while AICDs can restrict the premature production of gas once the wells are at the production stage. Gas flowing through the AICDs device is restricted more than oil. This design prevents excessive production/back-production of gas once the breakthrough happens in one or more compartments.

The application of advanced completions in EOR applications has been studied by the development of an explicit reservoir and well simulation model set up based on reservoir data from an unconventional oil field in North America. A unique hydraulic fracture modelling technique was used in this study to allow the well to be appropriately constructed in the simulation. Also, the impacts of various parameters including the heterogeneities in the reservoir and fracture properties, soaking and production times on the performance of EOR applications were studied. The results show the proper application of advanced well completion can improve huff & puff EOR recovery efficiency by 200% while mitigating the reservoir uncertainties and operational limits and minimising gas injection cost and soaking time in this application.

This paper also shares the experience and lessons learned with prediction models' complexities for the EOR projects in unconventional oil wells and the use of technology.
Role of Automated and Accurate Well Placement in Reducing Subsurface Complexities and Optimizing Geosteering – An Example from Complex Unconventional Reservoirs
Authors: Saikia Kalyan , Shanker Narayan
Published: November 2019

With the increasing demand for hydrocarbons, unconventional reservoirs are gaining prominence and account for a large percentage of oil and gas production. However, these unconventional reservoirs inevitably include challenges that must be carefully managed while planning an extraction strategy to yield maximum recovery. This paper demonstrates the advantages of an integrated and automated well placement workflow to improve geosteering in complex unconventional reservoirs with maximum hydrocarbon recovery.

Automated well placement technique is controlled by three primary components: (1) an integrated asset model; (2) availability of uninterrupted, real-time log data; and (3) appropriately selected well planning methods. Initially, a dynamically updatable model of subsurface geology is created that combines surface topography, and an initial well trajectory is planned. As the well progresses, new log data are added to the asset model, and an interpretation is made in real time. Incorporating real-time data helps to dynamically update the model and enable a comparison of planned vs. actual deviation surveys for course corrections. This procedure guides the geosteerer to update well plans, run feasibility analyses, and predict subsurface uncertainties ahead of drilling, thus, increasing the reservoir penetration and overall well productivity.

Automated well placement while drilling is a relatively new concept and requires collaboration across various disciplines. Currently, such techniques are gaining importance among operators of unconventional resources as it enhances accuracy in well positioning and provides better production while reducing costs, drilling risks, and uncertainties. In addition, when targeting very thin, geologically complex reservoir layers, it provides a holistic view of the dynamically changing asset. The use of this approach will enable oil and gas operators to make collaborative, cross-domain decisions and streamline existing unconventional workflows.
Reshaping Production Logging Execution Workflow Saving Significant Cost and Time for Kuwait Oil Company
Authors: Al-Obaidi Abdulmohsen , Al-Ibrahim Abdullah , Al-Dhafiri Abdulrahman , Al-Mehanna Hamad , Al-Haddad Mohammed , Al-Harbi Sultan , Ayyad Hazim , Mehraj Majid , Abdulrahim Khaled , Hernandez Guillermo
Published: November 2019

Digital Slickline (DSL) Technology for production logging has been successfully implemented in South East Kuwait (SEK) oil fields. This advanced technology enabled Kuwait Oil Company (KOC) to save significant amount of deferred production and operational cost without compromising on the data quality. In addition, it reshaped how the operator performed surveillance operations through a more efficient workflow.

A detailed analysis was carried out in more than 11 wells where production logging was acquired with DSL. Comparing the new workflow to the traditional workflow showed that DSL implementation saved around 51,000 barrels of deferred oil production and improved operational efficiency by 72% compared to the conventional workflow, without compromising on data quality during both real time and interpretation stages.

Based on these results, KOC decided to implement this workflow in majority of the wells and now it has become the standard for production profiling in ESP wells.
From Failure to Opportunity - Unearthing the Unconventional Choices
Authors: Al Awadhi Ibrahim , Sharma Ashok M. , Subramaniam Krishnan
Published: November 2019

Objective/Scope

A localized tube rupture was observed in the convection section of Fired heater. To address this, improve Integrity and avoid Process Safety concerns, the existing convection section required replacement. This paper presents an alternate approach followed to reduce operating costs by enhancing the heater performance and efficiency while addressing high heat flux issue.

Methods, Procedures, Process

The new convection section was designed with an increased coil surface area to enhance the heat recovery and optimize heat flux. Fin materials were changed from original carbon steel to SS410 in high temperature zone to minimize fin burn-off issues. The challenges were phenomenal, as the heater was 40 years old and new convection section is twice heavy and size than existing. In order to overcome, systematic engineering approach was adopted, from sizing new convection section with optimum heat flux, Mechanical design with FEA to verify structure integrity and foundation adequacy for increased loads. As a step toward safeguarding the tube from similar future failure, tube skin thermocouples were installed in shield tubes to facilitate continuous monitoring.

Results, Observations &Conclusions

Analysis confirmed integrity of the heater with minimum modification on anchor bolt avoiding need major foundation and structural upgrade. Two furnaces have been upgraded with new convection section and continuous monitoring for period more than 1 year has confirmed performance with no tube failure ensuring 100% HSE. Post project implementation resulted in more heat recovery from flue gases due to increased. Flue gas temperature leaving convection section was reduced from 450°C to 220°C. Consequently, required fuel gas consumption was reduced considerably by 9031 MT per year for two heaters. In conclusion, similar reductions in fuel gas consumption can be achieved over the equipment's extended service life.

The implementation has led to not only to increase in heater efficiency but in turn improved the heater duty for same burner capacity, there by supporting increase in plant throughput.

Novel/Additive Information

Conventional approach of replacing tube with improved metallurgy would have ensured process safety and structural integrity. However, the synchronized and pre-emptive engineering approach has yielded multiple benefits for the rest of the heater as well plant operational life. This also led to improved efficiency and Optimum Energy Conservation and save operating cost up to almost 1.1Million USD/year. Even a leak can lead us to peak if the opportunity is harvested in right way.
Start-Up & Commissioning Challenges of Sour Gas Injection Compressor Operating in Dense Phase
Authors: Singh Bhupinder , Aggarwal Rajdeep , Singh Harendra , Kamal Faris , Takeidinne Ousama
Published: November 2019

Gas injection compressors are playing major and vital role in oil and gas facilities for maintaining reservoir pressure and sustain production. However, operating experience of these facilities is still limited. Sour and high pressure gas injection compressors present unique challenges especially during start-up/commissioning. Failure of many start-up attempts can cause endless delays and can lead to production and revenue losses. This paper provides useful insights into these issues and their mitigation.

Gas injection compressors operate in very high pressure "Dense Phase" region. Dense phase is compressible fluid and exhibits properties of both liquid and gas. There is no clear boundary separating dense phase from liquid phase or dense phase from gas phase. Slight change in operating conditions can shift the fluid from dense phase to liquid or transition region resulting in unpredictable behavior in compressor/seal system. This can activate spurious shutdown due to either phase change or measurement errors under highly dynamic start-up conditions. Operating range has been studied to identify the issues and mitigation to avoid such conditions.

Detailed root cause analysis has been carried out to investigate full spectrum of operating and startup conditions for compressor as well as dry gas seal system. These are based on author's experience with startup and commissioning of several gas injection compressors which included spurious shutdowns and failure to start up. These have led to development of a robust procedure as well as selection of proper process conditions to successfully start the compressor that include issues such as: Design of dry gas seal system to avoid condensation /sulfur deposition and seal damageScrubber liquid level measurement and controlPotential compressor flooding due to layout and consequent draining issuesShutdown, settle-out and liquid handling during depressurizationPreferred inter stage pressure, temperature and operating region

Start-up and commissioning challenges due to above mentioned design issues have been successfully tested using dynamic simulation and implemented for smooth start-up of an existing gas injection compressor operating in dense phase region.

This paper provides useful insights into issues encountered during start up and commissioning of high pressure gas injection compressor operating in dense phase region and their mitigation. The proposed mitigations have been demonstrated using dynamic simulation and tested at site. Design strategy is provided to ensure more robust design in future for such high pressure gas injection compressor.
Solving the Deccan Trap Drilling Challenge with Innovative Ridged and Conical Diamond Elements Technology
Authors: Sharma Anshul , Narayanan Shine , Zayyan Mohammad , Prakash Shailesh , Raghav Sanjeev , Gounder Shwetha
Published: November 2019

Government of India has set an ambitious target of reducing hydrocarbon import. Increasing oil & gas production is one of the measures by which oil & gas import dependency can be reduced. Despite relatively low crude prices globally, substantial E&P activities have been carried out in the country in the last decade, which has witnessed an exponential increase in exploration of oil and gas reserves. Many new fields were discovered during this exploration campaign out of which, few are potential traps containing hydrocarbons. Kutch and Saurashtra Basin off Gujarat coast is one of the exploration fields that involves trap drilling to explore reservoir sands below. Recently for the very first time, in a decade, oil reserves have been discovered in prospective sedimentary basin of Saurashtra. (DGH India Outlook, 2017-18)

Drilling in this basin is characterized by slow rate of penetration (ROP), frequent bit trips, drill string failure, and high well cost. The 12 1/4-in section in this offshore block typically drills through very hard, abrasive and thick layers of Basaltic formation (known as Deccan Trap) with unconfined compressive strength (UCS) between 18-42 kpsi. Conventional polycrystalline diamond compact (PDC) bits and roller cone (RC) bits faced extreme cutting structure damage and delivered poor ROPs in this section. In this paper, challenges of drilling approximately 2,200 m of hard and abrasive Deccan Trap in the 12.25-in section is discussed along with a proposed solution of hybrid bit design by combining conical (CDE) and ridged (RDE) diamond elements.

Two new hybrid 8-bladed 16-mm bit were specifically designed for this application. The first bit drilled an interval of 952m with an average ROP of 1.9m/hr and the second bit drilled an interval of 960m with an average ROP of 1.83m/hr. Both the bits came out of the hole in good condition, thereby delivering a benchmark performance in drilling this challenging section. The runs resulted in 40% reduction in cost/meter for this section and saved 36 offshore days for the customer.
Troubleshooting Glycol Loss in Gas Dehydration Systems Using Data Analysis at Upstream Operation
Authors: Soliman Mohamed , Alwani Mohammed Abdo , Aiderous Abdullah Younis
Published: November 2019

The objective of this paper is to showcase the successful and innovative troubleshooting data analysis techniques to reduce glycol loss and to meet the product specifications in one of the gas dehydration systems in an upstream gas oil separation plant (GOSP). The gas dehydration system using Triethylene Glycol (TEG) is the most widely used and reliable gas dehydration system in upstream operation. These proven data analysis techniques were used to tackle major and chronic issues associated with gas dehydration system operation that lead to excessive glycol losses, glycol degradation, and off-specification products. Glycol loss is the most important operating problem in the gas dehydration system and it represents a concern to the operation personnel. Most dehydration units are designed for a loss of less than 1 pound of glycol per million standard cubic feet of natural gas treated, depending on the TEG contactor operating temperature.

In this paper, comprehensive data analysis of the potential root causes that aggravate undesired glycol losses degradation and off-specification products will be discussed along with solutions to minimize the expected impact. For example, operating the absorption vessel (contactor) or still column at high temperature will increase the glycol loss by vaporization. Also, the glycol losses occurring in the glycol regenerator section are usually caused by excessive reboiler temperature, which causes vaporization or thermal decomposition of glycol (TEG). In addition, excessive top temperature in the still column allows vaporized glycol to escape from the still column with the water vapor. Excessive contactor operating temperature could be the result of malfunction glycol cooler or high TEG flow rate. This paper will focus on a detailed case study in one of the running TEG systems at a gas-oil separation plant.
New PDC Bit with Hollowed Cutters: with Increased ROP and Longer Service Life
Authors: Zhang Hongying , Chen Huihui , Liu Feng , Wang Na , Huang Yanfu , Fang Zhimeng , Pan Xingming
Published: November 2019

A novel design of PDC bit with hollowed cutters is presented that uses the principle of hydraulic lubricating and water jetting mechanism to improve ROP. Engineering results show its advantage compared to solid fixed cutters which are commonly used in today’s drilling industry.

The structure of the new PDC bit is as follows: each cutter contains a specific fluid channel, which is tailor made; the bit body contains many fluid channels; Compared with the existing conventional PDC bit, the main distinctive features are: the cutters are hollowed, each cutter contains a fluid channel in the centre of itself; and the bit body has fluid passages which are communicating with each hollowed cutter, allowing the drilling fluid flows from the inside of the bit to the outside of each cutter.

The failures of a PDC bit are mostly due to premature wear or cracks of compound cutters; the wear or cracks are due to mechanical and thermal effects. To improve the service life of cutters can effectively increase the life of the drill bit. According to thermal stress analysis, the position where the frictional heat concentrated is in the centre of the cutter, which will result in the generation and expansion of thermal cracks, which in turn leads to failure of the cutter and loss of ROP. Therefore, the cutter with fluid passage will improve the way of thermal concentration and expansion, thereby prolonging the life of the drill bit, reducing the number of trips, improving single run drilling footage, therefore the drilling efficiency is increased. During the drilling operation, the rock cuttings cannot flow out timely, and may accumulate on the drill bit, which is commonly referred to as mud balling. The presence of mud balling will reduce the cutting capability of the drill bit and decrease the ROP. The new PDC bit with hollowed cutters has self-cooling and self-cleaning functions to mitigate the thermal effect, while the pressurized flow from the micro-hole of the cutter has the effect of water jetting, which in turn increases the ROP.

The novelty of the new PDC bit is in the capability to solve the issues of low ROP and short service life of today’s tough drilling conditions, to meet the requirement of a single trip to complete the total depth.
Famous Barriers within the Bowtie Levels Analysis: Creating Middle and Senior Management Understanding about the Relative Importance of Management Activities
Authors: Hudson Timothy , Hudson Peter
Published: November 2019

The paper discusses extending the use of the Frequency Adjusted Measured Effectiveness (FAME) methodology (SPE-190633) to the operational, organisational and cultural levels in bowties. The method enables risk management functions to steer senior management toward effective management actions at the middle management level, allows greater understanding of the cultural and regulatory factors impacting those management activities, and provides a clearer understanding of where the most important impact can be achieved through organisational change.

This paper develops Bowtie concepts by applying FAME (SPE-190633) to the bowtie ‘levels analysis’ (SPE 127180). The ‘levels analysis’ defines the barriers at the levels of a bowtie as the workplace (Level 1, L1), organisational (Level 2, L2), and cultural and regulatory factors (Level 3, L3). FAME quantifies the relative importance of barriers within bowtie systems as a whole. The paper uses these concepts to provide simple ways of providing middle and senior managers with understanding about how well their risks are being managed.

The disconnect between what management does and what actually needs to be done has been shown to contribute strongly to accidents. Without the support of analytical tools to steer decision-making, management activities are generally prioritised on an ad-hoc basis, usually guided by an individual manager's experience as well as senior management pressures. This can lead to important management activities not being conducted as rigorously as they require. The Levels Analysis improves understanding of the middle and senior management roles involved in the management of the risks of the operation, while the FAME methodology supports the understanding of the relative importance of those activities, allowing prioritisation. When applied this allows risk-based decision-making to be applied not only to frontline tasks but also to higher-level management functions. This approach, by looking at all the management functions controlling barriers, allows risk managers to communicate clearly the priority safety critical management functions require to senior managers.

This allows the conversation to change from "why wasn't he wearing his gloves?" to "how did we not have a start-up audit on this contract?" The emphasis is moved from immediate causes that are hard to control to factors that are within the span of control of middle and senior managers. This paper introduces a method for clearly communicating to middle and senior management what their own critical management functions are, which are most important and what they can and should be held accountable for.
Selection of Tubing and Completion for High Sour HPHT Gas Wells – A Success Story
Authors: Pimenta Gervasio , Bux Adeel , Ahmad Mubashir , Baslaib Mohamed , Al Jeelani Omar , Al Rumaithi Fahad , Turniyazov Nurlan
Published: November 2019

Selection of material for downhole completion is a challenging process for appraisal wells, where the uncertainties associated with the reservoir parameters need to be weighted and economically reasoned. This is particularly true for high sour, high temperature, high-pressure (HS-HPHT) gas appraisal wells, where the probability associated with potential release of gases needs to be as low as possible, as the consequences of a release can be very high and potentially fatal.

A corrosivity assessment was carried out for the material selection of tubing and liner of a HS-HTHP gas well with H2S and CO2 in excess of 40% and 10%, respectively. Uncertainties in the simulations were related to the amount of water, and condensate. Previous reservoir data suggested that elemental sulphur would not be present. The well was completed with a 25Cr35Ni alloy for a flow test period of 1 year.

Test separator data revealed a minor amount of water. After the test was completed, the tubing string was pulled out of hole. Visual inspection showed scattered shallow pitting, with some connections revealing crevice corrosion.

This paper describes post-exposure analysis of the completion tubing, relating pitting and crevice corrosion with the fluid and reservoir conditions.

Results of this real-time study allowed setting the requirements and standards for selecting downhole materials, considering the presence of water and elemental Sulphur in the HPHT sour atmosphere downhole.

Furthermore, recommendations were incorporated in the test of FFP materials in such harsh conditions to test against crevice corrosion in challenging reservoir conditions, as a fundamental parameter in the material selection process for FFD. This study represents a valuable document in the current ADNOC strategy of attraction of business partners for development of new concession blocks, especially for HS-HPHT gas and condensate reservoirs.
The New Development of Amphiphilic Polymer Profile Control Agent in High Temperature and High Salinity Reservoirs
Authors: Yang Hongbin , Kang Wanli , Zhang Hongwen , Zhou Bobo , Li Xinxin , Wang Fang
Published: November 2019

Profile control treatment is an effective technology to improve reservoir heterogeneity and decrease the watercut. Polymer gel has become the most widely used profile control agent. The most commonly used polymer in polymer gels is HPAM, which has poor adaptability in high temperature and high salinity reservoirs resulting in poor gel performance. Amphiphilic polymers have good viscosifying action in high temperature and high salinity reservoirs due to the polymer chain entanglement and hydrophobic chain association. In this paper, one amphiphilic polymer (PADC) was developed by introducing a betaine type functional monomer. In order to further improve the anti-temperature performance of PADC, the idea of using inorganic nanoparticles for enhancement was proposed. Based on this, a composite gel with good temperature and salt resistance was developed by adding crosslinking agent. The effects of nanosilica particle concentration, polymer concentration and crosslinking agent concentration on the gel performance of the composite gel were investigated systematically. The results showed that salt viscosifying action ability was related to the ionic strength. The higher the ionic strength, the larger the polymer molecular hydraulics radius. At the same time, the strength of hydrophobic association was improved and formed a denser spatial network structure. The synergistic effects made PADC have the characteristic of salt viscosifying action. It was also found that the viscoelasticity of the polymer solution changed from a viscous system to an elastic system by adding nano-silica, and apparent viscosity increased significantly. We have demonstrated that nano-silica surface will adsorb free polymer moleculesin solution, and form molecular brushes due to charge attraction and hydrogen bonding. The molecular brushes will adsorb and combine with the spatial network structure formed by the amphiphilic polymer. A significant improvement in the gel strength of composite polymer gel compared with organic polymer gel. Our work indicates that the composite gel based on amphiphilic polymer has significantly potential applications in high temperature and high salinity reservoirs, it has certain reference significance for stabilizing oil output and controlling water content for the similar reservoirs.