bluuebunny/crossref_metadata_2025 huggingface dataset:
Improved Reservoir Characterization of Flow Connectivity in Complex Carbonate Field, Using DepoGrid Model
Authors: Bellah Samir , Fletcher Kathryn , Gomes Jorge , Ben Jeddou Houcine , Ahmad Ammar , Su Shi
Published: November 2019

The Mishrif formation in Abu Dhabi comprises progradational shelf margin facies. The western platform sediments are characterized by stacked clinoforms of clean high energy carbonates, with generally good reservoir properties at the top deteriorating gradually toward the west flank. In contrast in the east the formation is thicker and characterized by more differentiated, coarsening, shoaling- upwards sequences. High quality reservoir facies occur only near the prograding shelf edges.

The reservoir in this study had finely layered pillar grid models of the field using onlap and offlap layering to capture the vertical property heterogeneity and layering within the clinoforms implied by the depositional environment. However, this grid structure posed challenges for flow simulation as there were unphysical barriers and connections across the clinoform boundaries caused by the pinching out layers at boundaries between clinoform units.

By construction, in a depogrid each clinoform may be independently gridded with coordinate lines that do not need to be continuous through the vertical extent of the reservoir. Layers within a sequence can truncate arbitrarily against bounding discontinuities since the cells are polyhedral and the grid globally unstructured. Therefore, an evaluation of the depogrid cut-cell grid was undertaken for the reservoir.

A volume-based model was constructed using horizon surfaces and fault surfaces extracted from the pillar grid model, and the depospace transform calculated. The depogrid was created using the same areal resolution as the pillar grid. The layer parameters were set to give approximately the same number of layers in each zone as the pillar grid. The rock type base properties from the pillar grid were upscaled onto the depogrid, in the interest of time, to populate the static depogrid model. Reservoir fluid properties, relative permeability, and capillary pressure curves were taken from existing simulation models of the field. A high-resolution reservoir simulator was then run on the depogrid model. Run time comparisons of the pillar and depogrid simulations were made

The evaluation concluded that the cut-cell stratigraphically layered depogrid provided a more geologically consistent representation of the complex stacked clinoform structural elements and required significantly fewer grid layers to achieve the required vertical resolution. The depogrid simulations could represent the expected connectivity for flow. Improved run times were observed
Best Practices and Technologies for Enhancing Produced Water Quality
Authors: White Ramsey , Alhamoud Abdullah
Published: November 2019

Objectives/Scope

A Saudi Aramco department operates 12 gas oil separation plants (GOSPs) that have water-oil separators (WOSEPs) for produced water deoiling. The water is then injected back into the reservoir to maintain pressure. This paper provides details of the operational best practices and technologies for ensuring that the produced water is within specification.

Methods, Procedures, Process

A thorough analysis was conducted to determine the areas of improvement by adjusting process parameters, enhancing the upstream process controls and implementing modifications in the WOSEP. The impact of all changes was measured by monitoring the quality of produced water, particularly the oil in water concentration, through frequent sampling. Moreover, design deficiencies were observed, which led to the proposal of specific WOSEP internal upgrades and new technologies for enhancing the deoiling performance. All recommendations were combined into a single roadmap for the department.

Results, Observations, Conclusions

Significant improvements in produced water quality were observed. This includes an 80% reduction in off-spec samples and a lower average oil in water concentration. The roadmap also includes proposals for major upgrades to the existing WOSEP design.

Novel/Additive Information

The WOSEP performance roadmap provides innovative yet simple best practices that can improve the deoiling efficiency. Moreover, it links WOSEP performance to process flow stability.
Laser Perforation: The Smart Completion
Authors: Batarseh Sameeh , San Roman Alerigi Damian , Al Harith Abdullah , Othman Haitham
Published: November 2019

Perforation is the commonly used well completion technology to establishing communication between the wellbore and hydrocarbon-bearing formations, this is critical for optimal production. The proposed new well completion in perforation technology utilizes high power lasers energy. The technology attracted the oil and gas industry due to its unique properties such as it is a non-explosive based perforation technology with precise control over the perforated tunnel's shape, size, and geometry. The laser energy also creates permeability in the perforated tunnel. The successful research effort led to field deployment strategy in the next two years. he laser completion system consists of the laser source to generate the energy, which mounted on a coiled tubing unit on the surface, fiber optics cable to transmit the energy to the downhole target and to the laser perforation tool. The principle of the tool is based on combining optical and mechanical components, the alignment of the optics inside the tool provides the ability to control and generate different beam shapes and sizes, these create the several perforated shots in any direction.

comparison made between the shaped charges perforation and the laser perforation, under the same conditions and same rock type. Pre and post-perforation measurements were conducted for comparisons. The tunnel that is perforated by the high power laser is clean with no compaction, deformation or melt, the result also shows the same in all rock types with improvement in the permeability along the perforated tunnels. Details analysis carried out using different methods such as imaging and thermal analysis.

High-power lasers provide controllable heat source while penetrating the formation that enhances flow properties especially in tight formation, continues efforts over the past two decades proven that laser perforation can create large perforation tunnels with a large diameter. Laser perforation applied on all types for rocks including unconventional tight sands.

The potential of the technology is that laser can be the next new smart perforation generation that will change current well perforation. The state-of-the-art high power lasers technology in downhole perforation provide an innovative and safe non-explosive technology. Precision in controlling the power, orientation, and the shape of the perforation beam are some of the properties of the technology that made it attractive for downhole applications.
Practical Application of Tensor Model in Laminated Sand Shale Analysis
Authors: Ariewijaya Aditya
Published: November 2019

Correctly evaluating reservoirs with thin laminations can be challenging. From a conventional perspective, this type of reservoir is often considered to be nonpay because of its low resistivity. Tensor models help improve resistivity using horizontal (RH) and vertical (RV) resistivity measurements from triaxial induction logging tools. In the absence of triaxial advanced measurements of RH and RV, tensor model equations using a conventional openhole (triple combo data) can be used.

This approach is based on rearranging the tensor model with the Moran-Gianzero equation and using several assumptions for unique cases. This method explains the workflow to calculate sand resistivity correctly using only openhole data as well as calculating the anisotropic shale resistivity that is often estimated from nearby shales. A mathematical method is preferred to obtain consistent results for anisotropic shale resistivity parameters to reduce calculation uncertainty. Sensitivity analyses are created to provide a sense of how these parameters affect the results on sand resistivity.

For a vertical well where relative dip is close to zero, RSd can be calculated without knowing the RshV. The same equation provides a 10% error on RSd at VLam<10% and relative dip <10°. At a higher relative dip and anisotropic shale resistivity, a cubic equation with a new coefficient is proposed. Sensitivity analyses are made to compare a true RSd and calculated RSd with changing RshH and RshV variables. The model demonstrates that a 10% change on RshH could cause a 30% error on RSd at VLam of 10%, while changes in RshV only begins to affect RSd up to 30% at VLam 70%. Graphical and mathematical methods are proposed to help prevent misestimating the RshH and RshV. The graphical method is preferred when a complete data set for all relative dip is available, while the mathematical method is preferred when the data set is limited.

Unique cases where the RSd can be calculated as well as demonstrations on how anisotropic shale resistivity parameters can be determined using only conventional openhole (triple combo) data are highlighted. The additional set of constraints on the iteration of the cubic equation represents an improvement of the previous study, whereas the proposed method to determine the RshH and RshV helps prevent estimation errors of these parameters and helps improve RSd calculation accuracy.
Optimization of Heavy Oil Recovery by Radio Frequency Heating: A Theoretical Approach with Experimental Modeling
Authors: Bapat Sarthak , Akhter Nadeem
Published: November 2019

Onsite recovery of heavy-oil is primarily done by thermal methods. The aim of these methods is to reduce viscosity of heavy oil to deploy it towards injection well. Unfortunately, these methods maybe inadequate for certain economic criteria and subject to environmental limitations. Additionally, they may not be compatible with certain types of reservoirs, examples: shales, deep reservoirs, etc. Recently, interest was devoted to electromagnetic heating with radiofrequency (RF) to overcome some of these problems. A theoretical model has been provided for Heavy Oil Recovery through RF waves which compete with the existing methods of EOR by thermal heating. A set of governing equations has been provided with an experimental model that proves the method more efficient than others. As a result, the interaction of an oscillating polar molecule with its neighbours takes place and it generates frictional heat, which raises the temperature of the medium.

In general, the EM heating process relies on preferential absorption of EM energy as the means of increasing temperature of dielectric materials. The ability of an EM wave to conduct energy to a medium is determined by the molecular composition of the medium. If the medium holds mobile molecules with molecular dipole moments, then torque is exerted on the polar molecules by the passing Electromagnetic waves and the alignment of dipole moments with the oscillating electric fields of the electromagnetic waves take place. As a result, the temperature of the medium is raised due to heat generated by friction as continuous encounters between oscillating polar molecules happen. Microwaves are very much effective to produce heat by getting sufficiently absorbed by the materials. Since crude oil is not a good absorber of microwaves, microwave receptors like activated carbon, nano-metal oxides, and polar solvents should be used to make the microwave process faster. Hence, further research is needed to implement the enhanced metal-nanoparticle incorporating electromagnetic heating (EMNIEH) at the field scale. In this case, the main question is how to inject nanoparticles into reservoir through the wellbore hole during EM heating.

Electromagnetic Heating is very much a substitute to aqueous thermal EOR methods for heavy oil recovery from shale reservoirs or high clay content or deep reservoirs. This technology can also be implemented in complex geological system as it is relatively less expensive and better for the environment. A theoretical model allows us to take stock of how we can optimize and increase the use of EM waves and RF to efficiently deploy it onsite.
New Techniques for Metal Sulfate Scale Removal from Production Pipelines and Wellbore Case Study Sidi Kerir for Petrochemical Co.
Authors: Salah Mohanad
Published: November 2019

This research present case study of sulphate scales found at water treatment unit, cooling water system and heat exchangers at Sidi Kerir Petrochemical Company Alexandria, Egypt, which declined overall production by 6%, about 250 million US. Dollar in losses 2018 due to unit's shutdown and flow restriction in pipelines. We tried many techniques like mechanical jet blasting using high-pressure water to crack the scale but it was a time-consuming root and need special equipment and large labour although it was not that efficient in areas with heat exposure and it cannot reach some areas. So we moved to next root for removing scales by chemical cleaning based on inorganic acid like hydrochloric acid, sulphuric acid,,, etc. although it can dissolve the scale in very limit efficiency but we didn't accept this method because those chemicals were very corrosive to metal surface like cast iron and stainless steel grade 304/316 also using those chemical present hard handling problem for adding or dilution. Therefore, we had to take the challenge to develop our new chemical cleaning methodology that combines between efficiency and safety. In new methodology, we developed new chemical formula based on mild organic acid mixture combined with sequencing agent, anti-re-deposition agent, wetting agent and pickling agent to chemically dissolve the scale in efficient and safe way.

The chemical cleaning technique was successful to dissolve the scale in very short time and in safe way to metal surface like cast iron and stainless steel. This invention is useful for the removal of sulphate scale like iron sulphate, calcium sulphate, barium sulphate and strontium sulphate from process equipment including pipes, pumps and storage tanks. It is also can be used to the removal of these scale deposits from other equipment such as boilers and heat exchangers.
HFE Implementation Journey in PDO, Benefits and Challenges
Authors: AlRashdi Abeer
Published: November 2019

Major process safety incidents such as Deepwater Horizon, BP Texas City and Piper Alpha have revealed that understanding Human Factors Engineering (HFE) is one of the biggest challenges faced in Oil & Gas Industry. PDO historical database has also identified high frequency of design-induced human errors resulting in incidents, which could have been prevented by proper integration of HFE at early design phases.

Whilst efforts to minimize incidents have conventionally concentrated on machinery and technology, prevention measures today also recognize the importance of HFE as a major contributor to operational safety and to the optimization of system performance.

The journey of implementing HFE design in PDO projects has focused on the following: Developing in house HFE expertise,Mandating HFE requirements at early design phases of projects through following a systematic process (Discipline Control Assurance Framework DCAF),Ensuring proper HFE awareness level is cascaded to all relevant stakeholders in projects at early engineering phases,Applying relevant learning's from previous audits/projects/incidents,Initiating online HFE simplified tools to aid the process of implementation,Emphasizing on formal HFE inputs during model reviews and,Verifying compliance to HFE design as several stages of projects.

However, the process of implementation, on the other hand, has faced several challenges and obstacles. Lack of integrating HFE at the design phase can be attributed to a host of factors including lack of appreciation of HFE core values by engineers and managers, limited HFE expertise in the industry, and other challenges. This results in a general reluctance to spend the time and money when it comes to HFE design related issues, and eventually, resulting in poor HFE integration in projects.

This paper explores the step-by step journey of implementing HFE requirements in PDO projects along with the challenges faced in inculcating good HFE design in projects and it highlights the lifecycle advantages of incorporating HFE in design. In addition to that, a story of success for implementing HFE requirements in major projects is showcased; which set out a roadmap for enabling future projects in oil and gas industry to achieve full compliance with HFE requirements.
New Opportunities and Challenges to Discover and Develop Unconventional Plays in the Middle East and North Africa: Critical Review
Authors: Ba Geri Mohammed , Ellafi Abdulaziz , Flori Ralph , Belhaij Azmi , Alkamil Ethar H.
Published: November 2019

Nowadays, as the worldwide consumption of hydrocarbon increases, while the conventional resources beings depleted, turning point toward unconventional reservoirs is crucial to producing more additional oil and gas from their massive reserves of hydrocarbon. As a result, exploration and operation companies gain attention recently for the investment in unconventional plays, such as shale and tight formations. A recent study by the U.S. Energy Information Administration (EIA) reported that the Middle East (ME) and North Africa (NF) region holds an enormous volume of recoverable oil and gas from unconventional resources. However, the evaluation process is at the early stage, and detailed information is still confidential with a limitation of the publication in terms of unconventional reservoirs potential. The objective of this research is to provide more information and build a comprehensive review of unconventional resources to bring the shale revolution to the ME and NF region. In addition, new opportunities, challenges, and risks will be introduced based on transferring acquiring experiences and technologies that have been applied in North American shale plays to similar formations in the ME and NF region. The workflow begins with reviewing and summarizing more than 100 conference papers, journal papers, and technical reports to gather detailed data on the geological description, reservoir characterization, geomechanical property, and operation history. Furthermore, simulation works, experimental studies, and pilot tests in the United States shale plays are used to build a database using the statistic approach to summarize and identify the range of parameters. The results are compared to similar unconventional plays in the region to establish guidelines for the exploration, development, and operation processes. This paper highlights the potential opportunities to access the unlocked formations in the region that holds substantial hydrocarbon resources.
An Integrated Approach to Optimize Field Development Plan Based on Uncertainty Analysis in a Giant Offshore Field
Authors: Zhao Wenyang , Al-Neaimi Ahmed Khaleefa , Sarsekov Arlen , Saif Omar Yousef , Abed Abdalla Abdel , Al-Feky Mohamed Helmy
Published: November 2019

With an increased maturity and complexity of the reservoir, an optimized field development plan implementation is critical to achieve the planned target and to ensure an optimum field recovery. The paper presents an optimized process with uncertainty analysis based on Monte Carlo Simulation for the purpose of optimizing the Medium Term Development Plan (MTDP) implementation.

The five year development plan of this giant offshore field has been successfully assessed based on this optimized approach. The integrated workflow consists of four main parts, including actual field technical rate tracking, DBC optimization, simulation results, and effective capacity with Monte Carlo simulation embedded. The dynamic situations could be taken care with these seamless coupled tools. The actual field technical rate has been tracked on a monthly base through a systematic and automated process. The reference decline ratio has been assumed based on historical production decline analysis. Besides, a floating decline based on simulation results is also added in order to capture the well closure due to gas production limitation. Field technical rate is the fundamental input for field development plan to derive the field sustainable oil production rate. It is dependent on both existing wells' performance and future wells' planning. Both the expected gain and drilling schedule of the planned wells are crucial to achieve the production target with reservoir pressure appropriately supported. Voidage Replacement Ratio has been applied to balance production and injection. Drilling plan could be revised accordingly. The production and injection balance can be visualized in the effective capacity tool, which will be used to further optimize the producer and injector plans. The requirements of producers and injectors are summarized and imported into the DBC optimization tool to evaluate new drilling schedule, which will be used in the effective capacity tool for an iteration loop.

Uncertainty analysis is critical to assure a field development plan. Uncertainties have been evaluated based on the factors' most probable range. Five major assumptions, including expected gain from new wells, drilling duration, decline ratio, put-on-production time, and operating efficiency, have been evaluated to assess the uncertainty. Mitigation actions could be proposed to assure the production plan.
Biogenic Gas Potential in Abu Dhabi
Authors: Taher Ahmed , Al Hanaee Ahmed , Frsnco Bernardo , Chitrao Amogh , Abdelaal Atef , Popa Desdemona
Published: November 2019

Recently there has been a growing interest in gas exploration, much of this focus has been directed toward thermogenic gas derived from cracking kerogen in the highly mature kitchens. However, a significant proportion of the global gas reserve is not thermogenic but of bacterial origin (Katz, 1995). Biogenic gas is an important exploration target because it occurs in geologically predictable circumstances, in areally widespread area, and in large quantities at shallow depths as free gas (Schneider et al, 2016).

The recent exploration wells drilled in the northeast onshore Abu Dhabi showed elevated total gas readings during the drilling of the Gachsaran formation. Consequently, mud-weight was increased to control the gas flow. In addition, the recorded wireline logs indicate the presence of relatively high hydrocarbon saturations in several high porous zones of Gachsaran and Asmari formations.

To assess the productivity and commerciality of the Biogenic gas potential in Abu Dhabi, several exploration wells are planned to be drilled before the end of 2019. The positive results of these wells will open the door for a new era of sweet gas exploration activities in Abu Dhabi and its surrounding areas. The primary gas reservoirs are thin carbonate and clastics layers in the Gachsaran Formation at a depth that ranges between 1600-5200 feet below sea level.

Organic carbon isotopes, Rock Eval analysis, TOC log data and gas shows analysis indicated that the methane gas found in the Gachsaran Formation is of a biogenic origin and sourced mainly from the organic-rich argillaceous limestone of the Middle Gachsaran.

Gachsaran formation is comprised of alternating thin layers of anhydrite, limestone, marl and shale sediments in addition to the presence of salt layers in the lower part. This mixed lithology resulted in the reservoirs property deterioration in particular by shale and anhydrite nodules cementation.

The biogenic basin areal extent, significant thickness of the Gachsaran in this basin and the organic richness distribution, conclude possible generation of a huge volume of biogenic gas in northeast onshore Abu Dhabi. However, additional work is required to estimate the volume of gas that is accumulated and that can be produced from the Gachsaran and Asmari formations.
Completion Solutions to Enable Well Kick-Off and Liquid Unloading for Downhole Gas Compression Applications
Authors: Lastra Rafael , Montoya Cesar , Bussear Terry , Strattan Scott
Published: November 2019

Downhole wet gas compression technology (DHWGC) is a relatively new artificial lift concept for gas wells that aims to boost production, maximize recovery and delay onset of liquid loading. By definition, wet gas compressors are capable to handle certain amount of liquids entrained in the gas, however, there are some circumstances where large amounts of liquids accumulate below the compressor and need to be removed to allow the gas well to flow. Liquids can accumulate below the downhole compressor after well intervention or as result of condensates accumulation during normal production. To this end, a means to enable liquids removal for Downhole wet gas compression applications must be developed.

The objective of this study was to identify completion solutions that enable liquids unloading below the compressor. This paper introduces a new concept with a simple well architecture that will enable continuous operation and eliminate needs of additional well interventions to remove liquids accumulation that occur during well shut-in operations.
Operations Readiness and Assurance - A Practical Example
Authors: Khan Umar Ali
Published: November 2019

This paper discusses the actual implementation of the Operations Readiness & Assurance (OR&A) process through the life cycle of a brownfield project in OMV's existing operations in black sea region. Importance of operations readiness and assurance, what it really is and how it is implemented are also elaborated briefly in this paper.

OMV's has a well-defined operations readiness and assurance system in place with detailed guidelines and steps for its implementation in any project that exceeds the threshold value of 20 mn Euros. Projects of lesser value can also utilize the system at a smaller scale.

The success of operations readiness and assurance implementation is only visible through the commissioning and into the operate phase of the project as this is the primary focus of the OR&A process. Ideally, a project should have a flawless startup and operation, however in the practical world some teething issues may appear during and after startup in major or complex projects even the ones in which OR&A is implemented. However as long as those teething issues are resolved soon and don't result in much production loss then the project can be termed to have had a relatively satisfactory implementation of operational readiness and assurance principles.

While many companies may consider OR&A as an additional overhead and while it may be difficult to measure the benefits of OR&A in financial terms, however the reality remains that an effective implementation of the principles of OR&A can have good result with respect to the success of the project with respect to delivering its objective
Surveillance Approach of Steam Management in Heavy Oil Reservoir-Oman
Authors: Mahruqi Hajer Al , Habsi Ali Al , Mohammed Hassan
Published: November 2019

Steam injection is one of the most common EOR methods adapted in heavy oil reservoirs. Steam improves the heavy oil mobility by reducing its viscosity via temperature increase. Steam Flood and Steam Cycle are the primary approaches applied widely in a steam EOR project.

Profit maximization of steam flood projects require good reservoir management practices including regular reviews to optimize steam injection. Steam management adjustments are both simple and complex. The steam management adjustments react against performance expectations, such as early or late production response at the production wells

An integrated work effort by the reservoir management team is imperative in the daily surveillance work. This work requires using geological maps, fence diagrams, permeability maps for identifying possible sand channels and preferential steam path, injection profile logs, injection rates/pressure and production data. Synthesizing all this data determines best locations to redistribute available steam. Expected response is lower steam oil ratios, lower wellhead temperature and lower well water cut rates.

This paper, it summarizes the workflow used for steam optimization process in one of Oman steam flood project. The workflow covers the identification through implementation phase where steam adjustments are required. These phases include review of geological description, petrophysical properties, and production and injection trends. This paper also discusses final KPI measures used to judge successful steam management adjustments.
Reservoir Modelling in the Shale Gas Reservoirs Based on Horizontal Wells and Seismic Inversion
Authors: Gai Shaohua , Jia Ailin , Wei Yunsheng
Published: November 2019

The seismic vertical resolution is too low to identify the vertical boundary and petrophysical properties of the thin shale layers inside the target precisely. This study focuses on structural and petrophysical modeling of shale reservoirs based on horizontal wells and seismic inversion.

Combined seismic trend surface with the well tops on horizontal wells, we calculated the top and bottom surface of the target formation, and obtained the structural surface of each small layer according to the thickness percentage of each layer from few vertical wells. Ultimately, the structural model is made. The horizontal trend of the petrophysical properties can be controlled by the seismic inversion results. The vertical trend of the petrophysical properties can be controlled by well logs. Constricted by the linear combination weighting of the horizontal and vertical trend, the petrophysical model is established.

The results show that the trajectory of the horizontal well in the target layer is accurate, and the layers are not intersected. The thickness of each layer is relatively even in plane, which is basically the same as that of the vertical well, indicating the characteristics of shale stable deposition. The discrepancy between the thickness of each layer in the model and those of the vertical wells is very small, especially in the main production layer 1, less than 0.1m. With the linear combination weighting, petrophysical properties show the bimodal distribution in vertical trend, which is in accordance with the regularities of petrophysical distributions from vertical wells, making up for the seismic low resolution in vertical direction.

The research shows the fine structural and petrophysical modeling of the thin shale reservoirs, which provide the credible spatial distribution network and petrophysical properties for further modeling.
Use of Optical Gas Imaging for Visualizing Gas Leakage and other Thermal Camera Applications in Oil & Gas Sector
Authors: Singh T.P.
Published: November 2019

An insight into Optical gas imaging (OGI) – Complete details on these applications. And apart from just visualizing gas, new age thermal cameras can provide lot of value through operational efficiency and safety in a variety of applications such as Furnace applications, Fire prevention, Fire fighting, electrical/mechanical/refractor, continuous monitoring, tank inspection and flare stack monitoring along with IR window details.

By T. P. Singh, Director (Ins) – Emerging Countries, FLIR Systems, Inc.

Full paper Details

The modern oil and gas industry’s practices – from extraction to refining – are depended on to be socially and environmentally responsible in terms of ecological mindfulness, regulatory compliance, and the safety of both workers and the communities surrounding operations. Thermal imaging, also called infrared (IR) thermography, provides a vehicle toward ensuring all these aims are met, while providing a tangible and justifiable return on investment (ROI). While optical gas imaging (OGI) plays the most recognized role in the oil and gas industry, thermal cameras can serve a variety of non-gas imaging applications in the industry as well.

This article discusses basic concepts of infrared technology and provides specific applications info that details the advantages of using thermal imaging over alternative technologies or methods.

Lets discuss basics first and then we move to different applications.
State of the Art Development in Annulus Evaluation
Authors: Gupta Shilpi , Govil Amit , Obando Guillermo , Winther Tonje , Delabroy Laurent
Published: November 2019

In an oilfield well, when the annulus contents behind the casing are evaluated using ultrasonic measurements, the properties of the borehole mud, such as acoustic impedance and fluid velocity, are critical input for the accurate determination of acoustic impedance of annulus material and its subsequent bond quality. In deviated or horizontal wells, mud settling, and subsequent segregation leads to azimuthal and depth uncertainties in annulus evaluation. Typically, due to gravity, mud segregates, with the light component at the top and heavier component at the lower side of the well. In a non-homogeneous mud, using a single mud impedance value for computing acoustic impedance of the annulus can lead to ambiguous answers with uncertainties. Traditionally, it has been a challenge to accurately measure and apply these variations in acoustic impedance of the mud to precisely interpret the bond quality in the annulus.

A novel pulse-echo processing scheme called R+ inversion, based on a 3-parameter inversion approach, eliminates, to a great extent, the dependence on prior knowledge of the borehole mud. The 3-parameter inversion can also reveal conditions such as mud deposition and segregation in deviated pipes. This new processing enables easier and accurate interpretation of the annular content together with essential information about the logging fluid.

Four case studies established the successful implementation of R+ inversion in deviated wells in the Norwegian Continental Shelf (NCS) with azimuthal uncertainties in the mud acoustic impedance to provide reliable annulus interpretation. These measurements correlate and are validated using sonic logs as well as flexural attenuation measurements, thus providing confidence in the results and decisions. The case studies compare acoustic impedance results using legacy processing and R+ inversion processing. The limitation to use the azimuthal variations of mud in the traditional processing sometimes leave unanswered questions related to the bond quality affecting the intervention decisions expected from the bond log. With the help of R+ inversion, the operator managed to take informed intervention decisions faster, thus saving rig time and cost. Four case studies are explained in the details that demonstrate and validate the importance of R+ inversion when borehole mud settling occurs azimuthally, thus overcoming previous limitations of mud impedance computation and usage.

Cement evaluation using R+ inversion enables accurate and critical decision making during new well construction, intervention, plugging, and abandonment in all conditions, irrespective of the casing sizes and cement types.
Moving to an Autonomous Artificial Lift Concept through Automatic ESP Restart
Authors: Khalaf Ahmed , Norman Bruce , Alquwizani Saud , Almalki Hussain , Ergesous Meshal , AlSowaier Mohammed
Published: November 2019

Electrical submersible pump (ESP) trips and unplanned shutdowns can be a major operational challenge for many oil fields. In most of these ESP trips, the ESP can be returned back to production after conducting proper troubleshooting at surface and without any downhole intervention. The process of manually restarting tripped ESPs can be a complex and costly operation, especially in an offshore environment. Alternatively, automatic ESP restart can offer great advantages by reducing the ESP downtime.

Many of the variable speed drives (VSDs) available in the market offer an auto restart feature that allows the ESP to be restarted automatically without human intervention. This paper presents the concept and the application of this technique. The activation of ESP auto restart requires considerable technical review of the different trip causes and the proper restart methodology for each. Auto restart of each trip type has to be programed differently to prevent possible harm to the ESP. Specific engineering measures and procedures shall be put in place to ensure personnel and equipment safety.

In this paper, some statistical tools for ESP trips and restarts are presented to measure the success of auto restart, its effectiveness, and its limitations. The obtained results from the ESP auto-restart technique show it to be both practical and beneficial; it can significantly reduce the time to put the ESP back in operation resulting in production advancement. In addition, continuous data collection and assessment of auto-restart events play an important factor in ensuring that auto-restart settings are properly applied and adjusted for each type of variable speed drive installed in the field. Finally, the paper provides several recommendations with suggested ways to improve the functionality of this feature.

The technique introduced in this paper can bring artificially lifted fields closer to an autonomous and intelligent concept of operations. The presented model can serve as a good benchmarking tool for future implementation of artificial lift automation.
Deferment of Mini Shut Down with Partial Automation of Manual Control
Authors: Al Dhaheri Abdulla Mubarak , Khalaf Ahmed
Published: November 2019

ADNOC LNG (Train 3) processes High Pressure gases from ADNOC Off shore and the gas goes through a series of processes to remove Hydrogen Sulphide & other impurities and gets dehydrated before the gases are processed to separate the various components as products. The Acid Gas Removal Unit is a hybrid arrangement of the basic Benfield Carbonate unit and Amine technologies. The Carbonate Unit, using Potassium Carbonate as the solvent, does the bulk of the Acid Gas removal from the feed gases.

Subsequent to restreaming of Train-3 after 2018 T/A, in the Acid Gas removal unit, Lean Carbonate Flash Drum level control valve 2C-LV-61 got stuck and became inoperable from DCS. Since then the level of Lean F/D 2C301 was controlled by operation of manual bypass valve in field along with frequent adjustment of Makeup water flow to Carbonate Reflux Drum 2C313 by DCS controller 2CFC0082. The valve 2C-LV-0061 could not be released for maintenance due to passing Isolation valves. To enable complete draining of the system and replacement / repair of the defective valves a mini-SD of Train 3 (minimum of 7 days) was planned in June’19. Seven days’ shut down for the sake of this repair would result in loss of production resulting in a revenue loss of US dollors35 million.

A specialist review meeting was conducted on 12th Feb and on 9th March 2019 with Operations, Process Engineering & Control Maintenance to discuss the alternative option of automating makeup water flow control (2CFC0082), with the objective of reducing daily field operations required to control carbonate flash drum level during steady state conditions, whilst also improving level control and retaining plant stability.

The new control scheme to cascade the level of Lean F/D to existing flow control 2CFC0082 was implemented vide minor DCS change MDCSC/008/19 on 21st March 2019. The Performance has been satisfactory during normal steady state operating conditions.

Based on the observations, it was recommended to, continue with Auto operation of FC0082 to control level of Lean Flash Drum during normal operation with field operator support to operate the LV61 bypass valve, in case of a programmed or unexpected upset in level of Carbonate flash drum.

Thus the Shut down was deferred successfully till the next planned turnaround opportunity resulting in an opportunity to save US dollors 35 million.

Statement of Issue: Soon after restreaming the train after Turnaround, an important control valve in the carbonate circuit of the LNG Train 3, namely 2-C-LV-0061, became inoperable while the Train was running. Attempts to isolate the valve failed due to passing isolation valves which made online repair impossible. A complete shut down of the Train to repair the defective valve would mean a revenue loss of US dollors 35 million due to loss of production (in addition to the impact of flaring).
Statistical Optimization of PDC Bit Designs Based on 3D Simulations Applied to Demanding Directional Applications
Authors: Pelfrene Gilles , Al-Ajmi Hadi , Bashir Jomah , Al-Otaibi Fahad , Al-Nuaimi Ahmad , Al-Jiran Hamad , Baroun Ahmad , Al-Kandari Abdulaziz , Huseen Talal , Mikhail Boktor , El-Genidy Ehab , Reboul Sebastien , Carlos Julien
Published: November 2019

Simulating the mechanical response of PDC drill bits contains a lot of uncertainties. Rock and fluid properties are generally poorly known, complex interactions occur downhole and physical models can hardly capture the full complexity of downhole phenomena. This paper presents a statistical approach that improves the reliability of the PDC bit design optimization process by ensuring that the expected directional behavior of the drill bit is robust over a well-defined range of drilling parameters.

It is first examined how uncertainty propagates through an accurate bit/rock interaction model which simulates numerically the interaction between a given PDC drill bit geometry and a given rock formation, both represented as 3D meshed surfaces. Series of simulations have been launched with simulation parameters defined as probability density functions. The focus has been set on directional drilling simulations where the drill bit is subjected to significant variations in contact loads on gage pads along its trajectory. A global sensitivity analysis has also been performed to identify the key parameters which control drilling performance.

Directional system parameters are critical in terms of steerability and tool face control, particularly in high dogleg severity applications. Based on these simulations, a statistical optimization strategy has then been implemented to ensure that the directional performance of the drill bit remains effective under a given uncertain drilling environment. Statistical analysis combined with drilling simulations indicated that ROP improvements could even be achieved without compromising steerability. A balanced bit design was selected and manufactured in an 8 1/2-in. model to drill a 714 ft section of a Kuwait field. The bit was run on a high dogleg rotary steerable system and directional assembly. The bit achieved the high steerability goals required by the application while showing a good compatibility with the directional tool. Moreover, ROP was increased by approximately 27% compared to offset wells, setting a record rate of penetration in the field.

Whereas statistical analyses are commonly conducted in the field of geosciences, it has rarely been applied in the field of drilling applications. The statistical bit design optimization strategy deployed in this work has allowed to improve both the drilling performance of the drill bit and its reliability.
Intelligent Planning of Drilling Trajectory Based on Computer Vision
Authors: Wang Han , Chen Dong , Ye Zhihui , Li Jun
Published: November 2019

The conventional well trajectory design mainly developed from spatial mathematical model e.g. arcs or cylindrical spiral lines method, focusing on seeking optimal kickoff point and curvature. However, the complex well trajectory design requires more sophisticated and efficient method, considering greater contact with reservoir pay zone, which means time consuming computation works based on conventional well trajectory design. The automated well trajectory planning can meet such requirements, based on reservoir area identification, reservoir matrix evaluation, wellbore trajectory path generation. The present study aims to develop this algorithm for automated drilling trajectory design without assistances from human experts. Based on the stratigraphic figure of a specific reservoir, the present algorithm is able to provide an optimal trajectory with more contact zone while still meeting the curvature requirement. An intelligent planning algorithm of drilling trajectory is proposed on basis of computer vision. Based on the stratigraphic figure of a specific reservoir, the present algorithm is able to provide an optimal trajectory with more contact zone. By converting the reservoir profile (pay zone) to digital matrix and evaluating the pay zone matrix, the optimal well path is able to be automated generated. The research finding can be potential applied in geosteering drilling or autumated drilling.
Molecule to Molecule M2M Water Injection Performance Review to Achieve Water Injection Excellence in PETRONAS – Part 1 Surface Operations
Authors: Hadi Sriyanta , Ab Wahab Mohammad Afiq , Nasron Budi Mawardi , Sharkawi Wira Abadi , A Latiff Nazri
Published: November 2019

Relevant to maximizing oil recovery, water injection is implemented for reservoir pressure maintenance and to maximize oil sweeping. The water injection involves both surface and subsurface matters. Since the objective is reservoir pressure maintenance and oil sweeping efficiency improvement, the subsurface domain includes reservoir engineering, geology and geophysics as well as the production technology. For surface operations, the water injection operation includes water injection source, water plant operations and water injection infrastructure. Water injection bottle neck and water quality issue may occur and damage the water injection efficiency. An idea of molecule to molecule (M2M) water injection performance review is raised to conduct a comprehensive and collaborative water injection review that involving many and outreach parties such as reservoir engineers, geologists, geophysicists, operation engineers, production chemists, production technologists, maintenance engineers, production planners and process engineers. The opportunity to include technical providers, partner representatives and host government representatives is taken in order to allow an effective discussion and quicken the maturing of relevant solution proposals. Comprehensive end to end review from the point of water source up to the point of producer is done to identify problem at each point, threats and improvement opportunities at every single node within the whole chain. With the M2M, water injection performance review has effectively provided an effective collaborative working environment as well as a learning avenue for young professionals that are involved in water injection matters. Many action items are resulted from the exercise and they are having high impact including safeguarding potential cost of USD 10 million per year for the water injection plant and infrastructure operations. In the short run, no disturbances for oil production and in the long run, the oil recovery can be maximized. Due to some limitation, this paper discusses only the surface water injection operations.
Asphaltene Management Leading to Significant Reduction of Production Deferment and Operation Maintenance in One of the Sour Fields in Southern Oman
Authors: Narwal Tushar , Alias Zaal , Kumar Kamlesh , Abri Zahir , Dickson Sara-Jane , Hadhrami Abdullah
Published: November 2019

In Southern Oman, PDO is producing from several critically sour fields (1-10% H2S). Initial flow assurance studies from these fields based on available data at the time did not predict asphaltene plugging issues in depletion mode for most of the fields. However, over the period, wells from one particular field (Field SA3) started experiencing asphaltene deposition in the wellbore, which initially affected only surveillance activities but later led to significant production deferment and posed operational challenges. This paper discusses the asphaltene management strategy developed by the team to tackle asphaltene problem in a systematic manner by improving the current asphaltene detection and cleanout techniques, which led to to reduction in unscheduled deferment by ~50% and the intervention costs by ~20-25%. This work also describes the potential asphaltene risks during gas injection based on an asphaltene study performed on downhole samples.