bluuebunny/crossref_metadata_2025 huggingface dataset:
Extending the Range of Cement Evaluation
Authors: AlArfaj Sarah , Fituri M. Aiman , Shastri Mukesh , Rane Nitin , Al-Kanderi Jassim , AlMohailain Muhanad , Baijal Sanjeev , Al-Qadhi Fahad , Ekpe Joseph , Al Farai Saleh
Published: March 2023

Well integrity assurance and zonal isolation, are the main pillars for any oil and gas well, it was a practice in the past to evaluate cement behind casings for casings smaller than 13 3/8 inch, however with the increase in drilling deeper and more challenging wells, the need for evaluating cement behind larger and thicker casings became a necessity.

Different logging companies have invested in their existing cement evaluation services and upgraded their tool designs, specifications, and increased tool operating range to address the larger and thicker casing requirements. By mid-2016, the upgraded tool measurements range was extended to evaluate up to 22-inch.

KOC in South-East asset started developing their Marrat deep reservoir back in 2018, these wells are designed with large surface casings ranging between (18 5/8-inch and 24-inch) across their main reservoirs (Burgan) and the shallow water and gas bearing formations (Dammam, Radhuma, Tayarat, and Mishrif). Dammam, Radhuma, Tayarat, and Mishrif formations, feature a highly fractured carbonate reservoir and comprise corrosive water and trapped gas pockets. The corrosive water and the trapped gas pockets pose future potential well integrity risks in the field, which implies the need for proper zonal isolation throughout the well and the field lifespan. These formations also comprise a low formation frac gradient, that raises the requirement for low-density cement ranging from 8.5 to 10.5 PPG to overcome the shallow loss zone.

The newly developed extended range for the ultrasonic cement evaluation tools can cover up to 18 5/8 inch surface casings for KOC, however, some additional tests, work, and modifications were required to accommodate the 24-inch casing, which will be discussed later in this paper.
Thermal Investigation of ESP Motor Temperature Rise with Focus on Heavy Oil Applications
Authors: Najmi Kamyar , Teves Ricardo , Zarate Guzman Nahun , Zhu David , Thompson Howard , Gunter Shawn
Published: March 2023

The generated heat inside a motor is one of the main factors limiting a motor operation. Electrical submersible pump (ESP) motor is not an exception from this limiting factor. Running an ESP motor above the rated temperature can cause serious mechanical and electrical damages to the motor and finally result in motor failure. Therefore, an accurate prediction of motor internal temperature can help not only with expansion of ESP operating envelope, enhancement of motor reliability and run life, but also reduces operating costs and power consumption (carbon reduction).

In addition to industry wide challenges to cool down motors, ESP motors have certain characteristics that make motor thermal management more challenging. ESP motors generally generate a lot of heat and heat dissipation is subject to environmental conditions (such as dynamic well multiphase fluid conditions, well bore geometry and chemistry etc.) that are not easily manageable.
Mechanical Shock Response Analysis of Rilling Microchips for Optimal Performance Evaluation
Authors: Tella Sherif Adekunle , Li Bondong , Li Sanguo , Zhan Guodong David
Published: March 2023

To precisely predict the fluctuation of wellbore properties, local overheating and guide the drilling trajectory in the wellbore during drilling operations, it is preferable to use cost-effective drilling microchips to collect real-time downhole data measurements while drilling. The drilling microchips usually consist of SoC, add-on memory, sensors and on-chip battery. However, the microchips can be subjected to mechanical shocks during the release and drilling operations which can induce interconnects and components failure and eventually leads to damage, loss of stored data and a low recovery rate. As the efficient performance of the drilling microchips can be constrained due to the shock loads, hence, it is essential to understand the peak response of the device when subjected to such suddenly applied stresses or designed response spectrum. The development and validation of simulation modeling approaches is the initial step in this direction. This paper will present the effects of varied shock loads and duration on the drilling microchips using two methods: response spectrum analysis and direct time stepping through mode superposition. It can be deduced that the sum of the effective modal masses for all computed eigenmodes is around 0.8947, 0.8912 and 0.9076 in z, y and x directions. Thus, these modes account for 89.47%, 89.12% and 90.76% of the dynamic forces in the z-direction, y-direction and x-direction respectively.
Development of a New Inhibitive Fluid to Mitigate Shale Drilling Problems
Authors: AlArfaj Mohammad , Alqahtani Hassan , Alsubaie Turki , alotaibi Mohammad
Published: March 2023

In oil and gas industry, drilling shale formations requires careful design of drilling fluids to control shale-fluid interactions and mitigate wellbore instability. As the aqueous phase of the fluid invades shale formations and contacts clay particles, that may cause shale swelling and disintegration. As a result, solids loading increase in the borehole and that might lead to tight holes and, eventually, stuck pipes. Also, the rate of penetration might be reduced due to low hole cleaning efficiency and bit balling. Therefore, differet types of inhibitive drilling fluids have been developed to counter act the interactions between the aquwous phase and clay particles.

In order to develop an inhibitive water-based mud capable of mitigating the adverse effects of shale-mud interactions, it is important to characterize the shale sample in terms of mineralogical composition. Also, the shale-mud interactions should be studied through a series of experimental dispersion.

This paper presents the results of characterization and testing one shale sample and its interactions with an inhibitive drilling fluid and a comparison to non-inhibitive drilling fluid.
Advancements in Remedial Sand Control Solutions - Successful Deployment in Three Well Campaign
Authors: McKay Eilidh , Wigg Nicola , Parrott Keith , Iqlima Baida
Published: March 2023

Regaining sand control integrity in existing completions has been become an increasing challenge to overcome in recent years. Sand control challenges can occur over the life of the well, in the initial completion design, failure of existing downhole equipment or due to increased water production in later life. All of which need to be addressed using a technology which does not succumb to the same fate as any existing technology. Conventional remedial sand control methods vary in complexity, cost, risk, longevity and have associated weaknesses often resulting in reduced production. A novel thru tubing remedial sand control solution has recently been deployed for an operator in Indonesia which can be run on coil tubing or slickline. It is designed to transit tight restrictions within the upper completion and still set and conform to larger casing/screen IDs where control of sand has been lost. The key to the technology is the use of a unique conformable open cell matrix polymer (OCMP) as the sand retention layer which enables the tool to be fully compressed during deployment but will enlarge when at depth, filling the annular gap. The OCMP creates a tortuous flow path and the polymeric nature of the filter removes the energy out of any sand grain impingement reducing erosional effects. We present a review of three recent well interventions in both oil and gas wells that utilized this technology.
Towards Real-Time Bad Hole Cleaning Problem Detection Through Adaptive Deep Learning Models
Authors: Nivlet Philippe , Bjorkevoll Knut Steinar , Tabib Mandar , Skogestad Jan Ole , Lund Bjornar , Nybo Roar , Rasheed Adil
Published: March 2023

Monitoring of Equivalent Circulating Density (ECD) may improve assessment of potential bad hole cleaning conditions if calculated and measured sufficiently accurately. Machine learning (ML) models can be used for predicting ECD integrating both along-string and surface drilling measurements and physics-based model (PBM) results, even though their generalization is often challenging. To remediate this generalizability issue, we present an adaptative predictive deep-learning model that is retrained with new measurements in real-time, conditionally that the new measurements are not detected as anomalies. Past ECD measurements, corresponding values predicted by a 1D PBM and other drilling measurements are used as input to a deep learning model, which is pretrained on historical drilling data without any hole cleaning problem. This model has two components: an anomaly detector, and a predictor. In this paper, both components are based on combinations of Long Short-Term Memory (LSTM) cells that allow (1) to account for data correlations between the different time series and between the different time stamps, and (2) generate future data conditioned to past observations. As drilling progresses, new data is proposed to the anomaly detector: if the network fails to reconstruct them correctly, an alarm is raised. Otherwise, the new data is used to retrain the models. We show the benefits of such an approach on two real examples from offshore Norway with increasing complexity: For the first one, with no major drilling issue, we simply use ECD from the PBM to predict ECD ahead of the bit. The second example had multiple issues linked with mud loss and poor hole cleaning. For this latter case, we used additional topside measurements to better constrain the ECD prediction.
The Evolution of Hard Rock Drilling in Norway: How New Technology Solved an Old Challenge
Authors: Baruffati Paul Pasquale , Ngueguim Marcel Emile
Published: March 2023

The Åsgard field in the Norwegian sea contains hard, abrasive, and high temperature formations and the reservoir had never been successfully drilled in a single slimhole run over 10 years. Thorough engineering analysis, the application of lessons learned, and the introduction of new generation technology produced a series of improvements. These advances define a sustainable and systematic approach to efficient, cost-effective hard rock drilling in the Norwegian Sea and elsewhere. The method was to define the limitations of the existing approach and then iterate improvements to the system to increase performance. The first step was to define the existing operating envelope: offset data – drilling, downhole, and post-well analysis – was reviewed and weak points were identified. Then, using the most appropriate lessons from hard rock environments worldwide, initial design changes were made to the drilling approach and procedures. These changes delivered the first failure-free well in the field. New technology was then introduced to expand the drilling envelope further and this culminated in the first single run slimhole section in the field. Flat time was drastically reduced, while ROP and borehole quality were improved. Through scrutiny of drilling dynamics, high frequency torsional resonance (HFTO) was revealed to be driving system mechanical inefficiencies. Log analysis enabled the correlation of the onset of HFTO to lithology type, and new drilling parameter limitations – principally management of Weight On Bit (WOB) – were then defined. Real-time drilling optimization engineers were enlisted to support this approach. Rock strength analysis and post-run equipment inspection determined the need for more durable bit and Bottom Hole Assembly (BHA) designs. A custom drill bit was designed and a ruggedized, new generation Rotary Steerable System (RSS) and Measurement and Logging While Drilling (MWD/LWD) suite introduced. Within the established operating framework, this new technology enabled enhanced drilling parameters to be applied and resulted in a 53% improvement in penetration rate. High density survey data from the new MWD/LWD platform showed that the new generation drilling technology delivered an extremely high quality wellbore, where the cumulative tortuosity was within 5% of the theoretical well plan. This allowed the installation of the completion string in a new record time, reducing the technical limit. Overall, flat time was reduced by 56% and then 76% versus the offset average. Robust, new generation technology and a rigid adherence to system limits as defined by advanced engineering analysis provided a framework for rapid continuous improvement and a blueprint for repeatable, efficient performance. This can be used to drive efficiency improvements in similar offshore hard rock environments elsewhere.
Sidetrack Trajectory Success Indicator
Authors: Hitchcock Graham , Watson Andrew , Alshalan Meshari
Published: March 2023

The drilling of a secondary wellbore departing from a primary wellbore, known as a sidetrack, is used for many reasons during wellbore construction. Sidetrack techniques and procedures are well established with all the major service companies. A typical sidetrack operation would consist of setting a deflector (whipstock), cutting a hole in the existing casing (window), and then drilling into the formation at the desired exit angle and direction (kick off) to produce a starting hole (rathole) for subsequent drilling. The sidetrack milling assembly would then be Pulled Out of Hole and the drilling bottom hole assembly (BHA) run in hole to continue drilling the secondary wellbore trajectory. If for some reason, the casing exit and desired departure of the sidetrack is not obtained, this will remain unknown until the subsequent drilling operation with Logging While Drilling (LWD) tools are run in hole and have extended the rathole. The failure to obtain and recognize the desired kickoff departure prior subsequent drilling operations can lead to significant Non Productive Time (NPT) and subsequent rectification costs.

This paper describes the development and successful testing of a compact sensor package located near the front of the sidetrack milling assembly. The sensor package is activated at surface and records inclination data during the sidetrack operation. When the sidetrack milling assembly is pulled out of hole the sensor is read wirelessly using a handheld reader once the milling assembly is at surface. The reader gives the operator a visual confirmation, or otherwise, that the desired sidetrack kick off departure has been achieved allowing informed decisions to be made on the next operational stage.
Water Management Challenges in Greater Burgan Field
Authors: Alkandari Shaikha , Al-Zankawi Omran , Alsaleh Zainab , Jaafar Dunya , Jasem Mariam , Mudvakkat Anandan , Khan Junaid , Alaassar Ahmad , Perez Godo , Rjabli Nuran
Published: March 2023

As oil fields mature, producing more oil out of maturing reservoirs entails more water production. It is essential to have a successful water management process to be introduce, one that can handle substantial volumes of water produced in order to sustain crude oil production.

At the early stage of the Greater Burgan Field water management was not a major concern. Most of its crude oil was dry and easy production with little water from Burgan & Wara reservoirs in Greater Burgan Field. With maturing of the field, South & East Kuwait Asset has started experiencing an increase in water production from its maturing reservoirs. Also starting water flooding in Wara reservoir to increase oil recovery increased water cut with oil production as expected. These changes made the production facilities to become constrained that cannot fully handle produced water volume and result in production deferral.

To mitigate the high water cut challenges, South East Kuwait set up a multidisciplinary team to review and come up with actions to tackle the produced water handling challenge.

The team looked at an operational initiative to maintain the long-term disposal option of disposing produced water into Shuaiba formation. Shuaiba formation is below Burgan reservoir. During drilling the drilling team encountered heavy fluid losses in Shuaiba. This experience led the study team to support the option of disposing effluent water into fractured Shuaiba carbonate.

Shuaiba formation is classify as carbonate formation, full of vugs and fractures resulted from dissolution due to ancient underground water movement, the dissolution led to collapse And creation of large vugs and fractures around the collapsed area. The collapsed area and fractures are the main mechanism for storage of effluent water and increasing disposal capacity for the production facility. The plan is to drill Horizontal disposal wells targeting the Karst to intercept those vugs and fractures. The team saw a promising option to drill in Shuaiba, to increase the chance of loss fluid circulation and enhance facility capacity.

After drilling few wells and encountering total loss in the horizontal fractured section, along the edge of the karst, and performing injectivity disposing test, the wells showed ability to take up high water rates more than (50,000 BWPD). Based on the success of these disposal wells, Production operations bottlenecks are resolved in disposal well capacity and increasing it to more than (500,000 BWPD). Disposing in Shuaiba, formation will not require any treatment facilities and is an environmentally friendly long-term option
Coiled Tubing Drilling Advancement with Smallest Shaped Diamond Cutting Element
Authors: Siddik Syed M. , Rojas Pablo , Barrera Jonathan Lee Quintero , Alraheb Mahmoud
Published: March 2023

This paper describes an innovative concept for the smallest polycrystalline diamond compact (PDC) cutter size with non-planar diamond table used on a fixed cutter drill bit. This unique PDC cutter significantly increases durability, enhancing the bit life to drill more footage in multi-lateral applications driven by motor or turbine in two different challenging formations. Collaboration between a national oil company and a drill bits provider resulted in achieving consistent records in footage while maintaining good rate of penetration (ROP).

This 8.2 mm diameter PDC cutter equipped with unique geometry was used on a 3.625 in. fixed cutter (PDC) drill bit design. Main objective of the unique geometry on this non-planar diamond table is to improve cooling efficiency compared to the standard diamond table of a PDC cutter. Traditionally, PDC cutter technology relies on the cutter's thermal stability and abrasion resistance. Often, those two properties may not provide sufficient durability in abrasive formations. Initially, this unique geometry was used on bigger PDC cutters including 13 mm and 16 mm where a performance improvement was achieved, leading to the decision to scale-down to the smallest PDC cutter size.

Two different 3.625 in. fixed-cutter drill bit designs were used with non-planar diamond table PDC cutters and successfully passed the client requirement and trial testing criteria. Based on the field deployment results, drilling performance in the field was monitored and compared to standard diamond table PDC drill bit designs also used in the past as the benchmark. Shaped non-planar diamond table bit designs surpassed the footage of standard diamond table PDC cutter bit designs by 12% and 36% respectively with two different bit designs. Other performance aspect including dull condition were also monitored and showed similar wear progression as seen with other bit designs used in the application.

This innovative concept demonstrates that the non-planar diamond table PDC cutter successfully delivers more footage per bit run. This led to increase overall performance with deployments on coiled tubing drilling rigs across this difficult drilling environment in the challenging wells drilled in the Middle East. The novel technology achieves all drilling objectives with fewer drill bits and fewer trips, delivering the target footage at improved ROP.
Cementing Methods When Encountering Wells with High Background Gases
Authors: Khuwayr Asim Al , Jezany Mahdy , Shine Joe , Kagongo Eliud
Published: March 2023

Drilling exploration wells can present challenges to well delivery with the more notable including unpredictable formation (in-situ) pressures. The unpredictable pressures, such as wells experiencing high background gases while drilling the openhole, place more emphasis on the ability to provide isolation successfully to ensure well integrity. In addition, the unpredictable pressures can affect the casing design as well as the wellbore stability, which can have logistical restraints associated with a remote location's response time. As a result, a method or series of practices led to cementing success providing the isolation required to ensure well integrity and deliver the well objectives safely.
Understanding the Key Factors Affecting Well Integrity in Horizontal Well Multistage Hydraulic Fracturing
Authors: Arshad Waheed , Khan Khaqan
Published: March 2023

With the significant increase in multistage hydraulic fracturing in the last two decades, occurrence of casing failures has also become noticeable, raising wellbore integrity concerns among operators worldwide. The consequences of casing failures can be varied, but in many cases they affect well production, wellbore accessibility, and, in some rare instances, present well control and associated risks.

In fact, tubular damage during fracturing is not caused by a single, consistent reason. Rather, it varies greatly across the industry. Investigators have identified several different factors that come into play when identifying tubular fatigue failure when exposed to high stress loads during pressure and temperature cycles in a multistage fracturing operation. Other contributing factors are well trajectory and borehole inclination with respect to the fracture plane, the quality of the cement bond, the development of "trapped pressures," or change in in-situ stresses that could initiate formation movement.

A parametric study was conducted using worldwide data to evaluate and determine the main factors controlling overall well integrity. Casing failure was defined as a reduction in the internal diameter of the pipe from its initial completion state before hydraulic fracturing. The failure events were studied and compared with the same factors in successful wells.

This paper provides an insight into the relationship between borehole condition (primarily hole size), well deviation, well azimuth, dogleg severity, pipe centralization, the type of hydraulic fracturing treatment performed (i.e., proppant frac or acid frac) and the risk of pipe deformation. By understanding the primary factors that affect well integrity, the likelihood of casing failure can be predicted and avoided ahead of time, save fracturing costs across high-risk areas, and not jeopardize production from multimillion dollar completions. Managing well integrity is essential for development of oil and gas resources while preserving the environment and assuring safety of personnel.
Well Monitoring New Concept Based on Artificial Lift Power Indicators, Identifying Failures and Minimizing Energy Consumption Costs Due to System Inefficiency
Authors: Coria Pablo , Devincenti Victor , Orozco Maivy
Published: March 2023

The search for energy efficiency and the reduction of operating costs in medium and high flow artificial lift systems is becoming increasingly relevant due to the incipient energy crises. Therefore, the need of developing methodologies and algorithms that allow a rapid, early and effective power consumption deviation identification in huge electro submersible system fields has become a priority need.

Using statistical tools and innovative calculation methods can generate energy deviations zones of analysis that are divided by ESP pumps models and types of producing wells; according to this identification, the required strategies for adjustment -based on the reference efficiency frameworks- are addressed. This process allows to quickly identify and visualize the inefficiencies of the system (Well - ESP) together with the result of the taken actions. Online monitoring can be performed daily, weekly or monthly.

This methodology for monitoring and identifying energy deviations allows -in an agile and dynamic way-, to identify and prioritize energy deviations of large ESP fields, referencing them to pre-established statistical standards, taking action by being able to detect and react early, making the exploitation of producing wells more efficient and increasing the run life of the system. Additionally, it allows detecting viable possibilities for adjustments and optimizations, such as a Green Pulling, reducing downtime and higher costs in ESP repairs, obtaining at the same time, competitive failure rates for complex exploitation oil fields. The time reduction, with the power deviation early notice, allows concentrating the analysis effort on management and improvement actions, which can be complemented with the influence of other relevant variables (motor temperature, % motor load, etc.) that affect the system.

Monitoring energy variables allows summing an economical impact in each operating point, directing the taking of actions towards an economic, ecological and sustainable strategy.

This paper brings the implementation results and the follow up of a methodology focused on algorithms based on energy indicators from flow rates, linked to the characteristics of ESP pumps. This monitoring process integrates production, electrical, economic and equipment positioning variables in fields with more than 1,200 ESP running.
Setting ESP Packer at High Inclination Intervals Using a Creative Completion Design Achieving 30% Completion Time Savings in a Middle East Oil Field
Authors: Almuallim Mustafa , Agarwal Rohit Kumar , Silva Paul , Shaikh Jaffar Al , Al-Herz Mohammad
Published: March 2023

After years of oil production, conventional ESP placement at shallow depth ~ inclination of 45° is no longer capable for production and thus the need to push the ESP deeper and closer to the reservoir at 55°-85° deviation is deemed necessary, which negatively impacts the ability to set packers using conventional slickline systems. A novel approach of setting ESP packers is presented in this paper, featuring a modified completion design that allows the packer to be set at any inclination without the use of conventional methods like coil tubing, wirelines, or slick lines.

To begin with, the paper provides an overview of technologies that are currently being used to overcome the challenges associated with setting production packers at an incline exceeding 45°. It introduces an alternative approach to set packer using a simple, yet an innovative modification in the design of completion assembly despite historical challenges associated with packer placement at highly deviated intervals. The Optimized system creatively integrates application of multiple fit to purpose technologies and valves assembly across the completion string. This assembly can be operated to allow string self-filling and holding pressure from above which provides a simple method of hydraulically setting ESP packer. Additionally, other technologies were used to ensure hydraulic cables and lines are safe and away from any potential pinch point especially while running through deviated intervals. Finally, study concludes with detailed design criteria and description, execution road map and contingencies.

This system was successfully implemented across 5 extended reach wells (ERD) with packer planed at an inclination range of 64° to 86°. Revised approaches enabled time reduction of over 30% compared to other wells across which packer was set with conventional, time consuming and risky operation like coiled tubing and wireline tractor. Optimized completion design is currently adopted by operator as standard practice to set ESP packer across highly deviated trajectories for both multi and single lateral extended reach oil producers in a particular field in the middle east.

The document provides a novel approach to set production packer at high inclination by utilization of optimized and simple completion design compared to expensive and time-consuming alternative approaches. This can easily be duplicated worldwide to optimize production packer setting especially at high inclination and thereby saving tremendous time and cost.
Salinity and Temperature Effects on Oily Produced Water Treatment Using Polyaluminium Chloride
Authors: Xu Limin , Han Ming , AlGhunaimi Fahd , Bataweel Mohammed
Published: March 2023

Polyaluminium chlorides (PAC) has replaced a large part of traditional aluminous coagulants for water treatment in recent years because of low dosage, high efficiency, low cost and convenient usage. This work studied the effects of salinity and temperature on the efficiency of PAC in removing oil and colloids from oily produced water (PW) and the potential of PAC for high salinity PW treatment.

Minghua produced water (Di-MHPW) with salinity of 2,815 mg/L and high salinity produced water (HSPW) with salinity of 102,290 mg/L were used in this work. The efficiency of PAC and the optimal dosage were investigated by stability analyzer which allows a step-by-step vertical scanning of the dispersions. The separation time, floc volume and water quality after treatment could be obtained by stability analyzer.

Transmission intensity was used to evaluate the oil-water separation in PW. High transmission intensity indicates low oil content. Without PAC, HSPW presented faster increase in transmission than low salinity PW indicating poorer stability. The zeta potential of oil drops and colloids in low salinity PW (2,815 mg/L) was −20.4mV. High salinity (102,290 mg/L) increased the zeta potential to −2.2mV, which makes the oil-in-water (O/W) emulsion unstable than low salinity PW. With the addition of PAC, HSPW results in slightly lower transmission with less floc volume. This could be explained by the floc size after the addition of PAC in two PWs. The size of formed floc in HSPW was much smaller than that in MHPW leading to slower separation of floc from aqueous phase and lower transmission intensity. Increasing the temperature enhanced the PAC efficiency in removing oil and suspended solids in both high and low salinity PWs. However, the floc volume also increased especially in Di-MHPW resulting in less water volume. In HSPW, the temperature effect on floc volume was not obvious. Though high salinity reduces the performance of PAC in water treatment, it is still an efficient flocculant for HSPW treatment with high flocculation efficiency, small floc volume and short separation time.

This work provides the insight of oily produced water treatment using PAC and the effect of salinity and temperature. The results are helpful to develop novel flocculants used for high salinity produced water treatment.
Review of Electrical Motor Technologies for ESP Applications
Authors: Wrighton Chris , Vlad Rusu Alexandru , Lacchetti Matteo , Smith Alexander
Published: March 2023

The electrical submersible pump (ESP) is a key artificial lift enabler within the oil industry. Since their launch in late 1920s, induction motors have been the main motor technology used in ESPs. Recent advancements in technology have opened opportunities for the development of higher performance and more efficient topologies for electrical machines. This paper aims to provide a review of different motor technologies in the well oil and water fluid lifting industry.

The analysis in this paper is constructed around a comparison between several electrical machine technologies when exposed to the harsh downhole environment. The dimensions of each machine are similar and provide a fair comparison. The advantages and drawbacks of each motor are presented in respect to key mechanical or electrical considerations. Solutions are recommended when there is evidence from previous work, and several questions are raised for the feasibility of certain topologies in respect to the new challenges.

Results show why the induction machine (IM) was selected by ESP providers in late 1920s and why it still has value nearly 100 years later. Permanent magnet machines (PMMs) offer higher power density levels in a smaller package. Synchronous reluctance motors (SyncR) offer a more robust and cheaper alternative, but the design is relatively new and further analysis is still required. Advancements in switched reluctance machines (SRMs) allows for the development of a motor with IM torque capabilities. Both SRM and BLDC (brushless DC) require pulse width modulation (PWM) square-pulse drives, which may prove to be a challenge when driven over a long cable. This paper emphasises the importance of a proper analysis of each motor technology in respect to a particular application. The design of electrical machines should be tailored around the specification of each environment to provide a more robust and efficient system.

Although some literature is available on the comparison of PMM and IM in the artificial lift (AL) industry, it seems to promote PMMs with little attempt to suggest improvements for traditional IM topologies, which still offer many benefits in terms of ease of manufacture, robustness and capability to operate in extreme environments such as with high temperatures. This paper discusses several other technologies that have not previously been considered. The aim of the paper is to provide a holistic view of the possible problems each technology will face in the downhole environment and inform future work on possible design improvements for the most promising technologies. In addition, the paper will provide a comparative assessment of the different motor technologies in terms of their strength and weaknesses, and also issues that should be addressed for ESP applications.
Starter Wellhead: Achieving Mechanical Barrier Isolation in Large Casings Annuli While Countering Wellhead Thermal Growth
Authors: Mukhlifi Mohammed Eid , Wirawan Pandu , Alamer Mansour Abdullah
Published: March 2023

This paper describes the method and apparatus of the Low-Pressure Starter Wellhead System used for 36" and 30" conductor casings to provide the required wellhead sealing integrity for surface formations that have the potential to release formation fluids to environment during the well life cycle without restricting the casing thermal growth. The current industry approach is to rely on cement as the only barrier for casings annuli larger than 24" to seal off shallow hydrocarbon formations without any consideration for thermal growth resulting from well production.

Cement, the current barrier for surface casings (greater than 24" size), is prone to failure due to cracks resulted from the wellhead thermal growth as well as cement placement challenges. Therefore, this necessitates mechanical means of preventing hydrocarbon or water release to atmosphere via proper and sustainable solutions. This will provide the required support to prevent any negative impact on the environment, risks to personnel and to assets. Risks will be higher if the well is close to residential/ populated area and/or located in offshore environment.

The Low-Pressure Starter Wellhead System is new design concept in oil and gas industry (Patent Number: US11396785B2) as currently there are no available technologies to provide mechanical sealing for big surface casings while encountering thermal growth. It will provide a complete solution to isolate surface zones, provide seal and load integrity and cater for the casing thermal growth during the well production lifecycle. The new design, also, will facilitate the drilling operations while maintaining the well control capability at all times.

The benefits of the new device are significant. Achieving mechanical isolation for big casing sizes greatly enhances well integrity, especially for wells with shallow hydrocarbon or water formations. Accommodating for wellhead thermal expansion due to high well temperature provides a redundancy and eliminates the associated challenges with cement failures and formation fluid release to the atmosphere. This results in substantial cost avoidance, safety improvement and better environmental protection.

Sealing potential problematic surface formations is paramount for any well integrity considering the current industry gap with these large conductor sizes. This system presents a unique design in the oil and gas industry to establish a mechanical barrier for larger casings while accommodating for wellhead thermal growth.
Well Integrity Challenges while Drilling in High Pressure and Narrow Window Environment: A Case Study of a Deep Gas Field in the Middle East
Authors: Ovwigho Efe Mulumba , Almomen Mohammed Sami , Corona Mauricio , Terrez Jose
Published: March 2023

While drilling the 12" section, a water bearing formation is encountered prior to reaching the target gas reservoir formation. This formation is sporadically-charged across the field requiring a KMW up to 21 ppg. This poses major well integrity challenges as it becomes critical to avoid losses in the resulting narrow mud window and ensuring proper cement placement. Inability to predict the mud window makes it impossible to define the drilling strategy to implement.

To understand the drilling challenges, in-depth offset wells analysis was performed. Based on mud weights required to drill across the reference formation, the heat-map for historical KMW was created based on confirmed well control events. It was difficult to predict formation-flow potential. Field geomechanics studies were then carried out to correlate the mapping done earlier. Once possibility of encountering abnormally pressured formation is flagged, in order prevent drilling risks such as loss circulation and poor cementing placement, proactive measures such as: Improved influx monitoring, drilling/cementing fluids optimization, liner-and-tieback system implementation, Managed Pressure Drilling/Cementing, optimized casing design were put in place.

The integrated approach led to quick influx detection, proper definition of mud window, i.e. Pore Pressure and Fracture Gradient together, helped to prevent the losses, design of fit-for-purpose bridging strategy to ensure full drilling fluid column at all time while avoiding the cost associated with fluid losses. Drilling the section with Managed Pressure Drilling system (MPD) and low mud weight led to achievement of high ROP leading to substantial time saving. The Liner string was run and Managed Pressure Cementing (MPC) was implemented to manage the equivalent circulating density (ECD), avoid losses and ensure good zonal isolation. Overall non-productive time was reduced by 40% as compared to the offset wells in the area.

Integrated drilling approach delivers great gains when there is good understanding of the well integrity challenges and solutions are tailored to solve identified problems.
Polymeric Water Based DIF (Drill-in Fluid) Improved Design to Stabilize Complex Wellbores
Authors: Chinea Gonzalo , Moroni Luigi , Shujath Ali Syed , Kaageson-Loe Nils
Published: March 2023

The design of a drill-in fluid (DIF) requires an in depth understanding of the reservoir formation characteristics in order to minimize production impairment through processes such as fines migration and clay swelling. This is a, relatively, well understood design process for simple homogenous reservoirs. More complex wells, where shales are exposed in the reservoir section or reservoirs are depleted, may require additional products to maintain wellbore stability and allow the well to be completed. This paper assesses the impact on formation damage from the addition of these wellbore strengthening products.

Polymeric water based DIFs contain calcium carbonate bridging particles which can be dissolved with acid, and biopolymers which can be degraded with enzymes. Products used for wellbore strengthening usually include graphitic materials, which are neither acid soluble nor degradable by enzymes. This study evaluated the effect of these addition materials in combination with calcium carbonate through a series of Return Permeability tests to determine their effect on sandstone formations. Return Permeability tests were performed to simulate well operations in a laboratory environment, during which the measure of relative permeability is used to quantify any change in permeability caused when a fluid is applied to a rock sample. For comparison purposes, baseline tests with standard polymeric water based DIFs were initially performed. Subsequently, different additives were incorporated in each system to evaluate their effect on the return permeability.

This paper presents the results of an extensive study investigating the effect on return permeability from the addition of graphitic and polymer materials used for wellbore strengthening, using two polymeric water based DIFs. The results show that, under the correct conditions, the addition of these products to the fluid formulation for the enhancement of wellbore stability does not significantly impair the permeability of the formation as had previously been believed.
Executing the Digital Well Plan - Enhancing Process Automation
Authors: Hummes Olof , Macpherson John D. , Bone Kimberley , Marwah Gaurav , Arévalo Pedro , Forshaw Matthew
Published: March 2023

Automation of well construction combines process and machine automation to deliver cost savings and efficiency gains, alongside safer operations and faster collaborative decision making. Integration of well planning and execution improves performance, minimizes risk, and creates the framework for batch control of well construction. Generating intuitive and standardized insights from historical and live data streams enables reducing uncertainty and driving technical limit performance at every stage, for the safest and most economical well delivery possible.

Remote operations have become standard practice in well construction and drilling automation is rapidly growing. Machine-learning based models can predict hazards and best operating parameters. The paper describes how these elements are combined to easily analyze offset well data from multiple sources for performance benchmarking, deep technical analysis, and risk management. Integration with physics-based models (the digital-twin) establishes a coherent execution roadmap, a real-time digital recipe that is directly used in rigsite automation. During execution, model assumptions are replaced by live sensor data. Those models are then re-calculated in real-time for automated process control and become available for future planning.

The viability of integrated well planning and automation systems is no longer disputed, and industry focus has shifted towards proving the potential of this approach. Pertinent case examples from drilling operations are examined in the paper, including optimizing performance through harnessing analytics of large data sets from offset wells, and on exploring the integration of AI techniques for risk prediction and mitigation. The insights gained, coupled with the digital well plan, are instrumental for optimization and automation of tripping equipment in and out of hole, and of drilling ahead operations.

Integrating the digital well plan with "lessons learned" from the analysis of all available data and using a digital-twin concept with physics-based and data driven models, provides the foundation for the next step in process automation: the creation of digital procedures for process automation of well construction. This capability extends the cost savings and efficiency gains realized in recent years through remote operations.
Prediction of Slug Length for High Pressure Gas/Liquid Two-Phase Flow in Horizontal and Slightly Inclined Pipes
Authors: Al-Safran Eissa , Aql Ahmed
Published: March 2023

Slug flow in pipelines is the most common flow pattern. Slug length is crucial characteristic for pipeline and downstream separation facility design and operation. In addition, mechanistic two- phase flow models require slug length as closure relationship to solve for pressure gradient and average liquid holdup in slug flow. However, the existing slug length closure relationships developed for low pressure are found to poorly perform in high-pressure conditions, i.e. high gas- to-liquid density ratio high, resulting in high uncertainty predictions of slug length, pressure gradient and liquid holdup. This work aims to propose a mechanistic slug length model and to identify the optimal closure relationship for high-pressure condition through error minimization technique using Genetic Algorithm. In addition, the identified set of closure relationships are found to match the physics of slug flow under the investigated conditions. As a result, the proposed model result in a coefficient of determination R2 = 0.85 and an Absolute Average Error (AAE) approximately equals 70% outperforming the best-performing exiting model in the literature.
Heavy Duty Robotic Fishing Allowed to Restore Injectivity in Critical Well – A Case Study
Authors: Nobile Blanco Juan Jose , Prabhakaran Sudesh , Shiwan Shiwanshu , Rout Amitav , Ting David
Published: March 2023

An offshore injection well was out of operation after unsuccessful wellhead maintenance operation, when a slickline Bottom Hole Assembly (BHA) was stuck inside Subsurface Safety Valve (SSSV). Several fishing attempts with variety of technologies were unsuccessful. Heavy Duty robotic fishing tools were used to retrieve the fish (acid syringe and soak sleeve along with slickline assembly) from SSSV, restore injection, and provide well integrity.

Analysis of unsuccessful fishing attempts suggested that the main reason for failures to achieve the goal was inability to provide sufficient force in controlled manner (without jarring), while there were no issues to latch the top of fish. Robotic fishing tool consisting of stroker tool with 100,000-lbf force available, reinforced with precise force and piston position control, in tandem with heavy duty overshot was proposed for operation. An onshore test, replicating the downhole scenario, was performed during the preparation phase to prove the concept and evaluate the functionality of the tools.

Fishing operation proven itself complicated - after successful latch and applied overpull, the fish started to move up for limited distance as long as stable upward force was applied. Series of strokes within same run were not able to completely free the tool, so the fishing tool was disconnected from the fish and pulled to surface to be replaced with fresh one. The real-time readout and achieved progress suggested that fishing strategy was adequate, and more runs were required in same configuration. Total four runs with numerous strokes were required to unstuck fish completely so it could be pulled to surface by strength of e-line cable. After retrieving the complete fish, it was possible to perform a successful inflow test to confirm SSSV being operational and put the well back on injection in a reasonable amount of time.
First Time Ever Rigless Securement of Offshore Gas Well with Deep Plug Prior Workover
Authors: Mata Gilberto , Aghazada Kamal , Alghrairy Mohammad
Published: March 2023

A proper deep isolation of high-pressure sour gas reservoirs through Corrosion Resistance Alloy (CRA) tubing had been a real challenge for offshore gas operations owing to the inherent limitations present in all rigless operations needed to accomplish this task. Moreover, the presence of high shut-in gas pressures is a major challenge to perform wireline operations needed to run and set the desired flow-barrier plug. Finding a suitable operational procedure, sourcing the adequate tools, performing a well-coordinated operation in a short period of time were the key factors identified to deliver a recently field-proven solution to properly secure and isolate an offshore gas well affected by gas passage through control line due to leaking piston seal of Tubing Retrievable Sub-Surface Safety Valve (TRSSSV).

This paper systematically describes the first ever successful operational approach implemented rigless to set a deep flow-barrier plug on wireline across CRA tubing to safely bleed-off all gas recorded passing through the TRSSSV's control line. This marked a milestone for rigless operations for the operator in their effort to secure problematic gas wells for workover in offshore operations.