bluuebunny/crossref_metadata_2025 huggingface dataset:
Hydraulic Casing Reamer Shoe Lands Casing in Problematic Wellbores
Authors: Pearson Allan , Luchak Mark , Curle Robert
Published: March 2023

Using a hydraulic casing reamer shoe (HSRT: Hi-Speed Reaming Tool) in place of a standard casing float shoe provides the ability to ream through formation tight spots on demand. With the casing string static or in dynamic motion (reciprocating up and down) the high RPM jetting action of the hydraulic reamer shoe removes obstacles such as swelling shales, dynamic salt formation movement, under gauged hole in medium to soft formations and micro doglegs. The tool also assists with navigating high angle entry points in horizontal / directional kick off points / multi-lateral completion entries, thus protecting any deformation of casing accessories such as centralizers and liner hangers from accidentally setting.

This is achieved by circulating through the casing via circulating head (or top drive equipped with a casing running tool) to activate the HSRT internal drive to provide additional circulation velocity with the speed created by the rotating HSRT. Turbulent flow cleans out the accumulated cuttings in the wellbore that can cause mechanical sticking and/or increased drag forces in the horizontal section if cuttings and solids are not effectively reaching the surface.

Although a wiper trip with a bit is still a common industry practice prior to running casing to condition the wellbore, there can be drawbacks such as formation exposure time to drilling fluids. These can be problematic and lead to added time and additional project costs. New casing running technologies such as the HSRT can save hours to days of rig time by removal of the previous noted instances.

The HSRT hydraulic casing reamer shoe was conceived to assist with landing casing and liners through problematic formations that would not allow casing to pass using conventional methods, while at the same time being cost-effective and reducing rig time during deployment. The reaming shoe must also be adaptable to all casing completion configurations, casing connections and casing sizes available in the market upwards of 13-5/8″. Since the HSRT becomes part of the wellbore construction it is compatible with other casing tools and accessories such as float collars, liner hangers and today's standard down hole equipment. In addition, some casing tools such as liner hangers do have pressure limitations, so the use of a burst disk can be added for safety during deployment to further ensure a successful deployment.

This paper will outline the development of this technology and include international and domestic case histories outlining the tools’ use.
Switched Reluctance Motor Operation Using Three Conductor Electric Submersible Pump Cable
Authors: Adams Robert , Xiao Jinjiang , Harrist Jonathan , Deffenbaugh Max
Published: March 2023

Switched reluctance motors have advantages over traditional three phase induction motors for downhole electric submersible pump systems. Controlling an switched reluctance motor systems requires precisely timed waveforms issued from the surface motor controller to the downhole electric motor, which are distorted by the long cabling required between the surface controller and the downhole motor. Additionally, the motor architecture needs to be capable of operation using the existing three-conductor infrastructure available for elecic submersible pumps. A novel surface controller and switched reluctance motor architecture capable of controlling a downhole motor system over long three-conductor cable lengths is developed and demonstrated.
Delaying Multiphase Pump Gas-Lock in High-GVF Flows Using High-Speed Operation
Authors: Ejim Chidirim , Xiao Jinjiang , Lee Woon , Zabala Wilson
Published: March 2023

Many pumping systems tend to lose pressure boosting capability at high intake gas volume fractions (GVF) resulting in gas-lock. Delaying occurrence of gas-lock is beneficial to extending the operating envelope of these pumping systems. This study presents the results of operating a multiphase pump at speeds higher than typical, conventional field applications, in addition to incorporating a flow-conditioning device at pump inlet. These attributes delayed occurrence of multiphase gas-lock to intake GVFs up to 98%.

The multiphase pump tested had a 5.38-inch housing outer diameter and shaft rotational speed of 6000 revolutions per minute (RPM). A nozzle was installed at the pump inlet to facilitate homogenization. The range of total volume flow rate of air and water at pump intake was between about 4900 to 7600 barrels per day (BPD), with intake pressures approximately 50 psig. The total intake volume flow rates were varied and the pump pressure boost was measured until the pump gas-locked.

The results showed that for the total volume flow rates tested, the multiphase pump was able to provide pressure boost of about 55psi at an intake GVF of 91%. For other flow conditions when the intake GVF was increased to 98%, the multiphase pump provided a 10 psi pressure boost. An observation during the test was the gas-liquid mixture flow through a nozzle resulted in a very fine spray mist. With the nozzle installed at the pump intake, a more stable pump operation was achieved throughout the tests. In conclusion, operating the pump at speeds of 6000 RPM facilitated extension of the operating condition when gas-lock occurred in the multiphase pump. Installing a nozzle device was beneficial in conditioning the flow at entry to the pump to ensure stable operating conditions. These findings are being incorporated in a field prototype version of the pump to handle higher volumes of gas and liquid in the field.

This study mainly highlights the method used to delay gas-lock in a multiphase pump. Operating the pump at higher than conventional speeds and installing components at the pump inlet to condition the flow are beneficial to ensure the pump continues to deliver pressure boost for intake GVFs up to 98%. Extending multiphase pump operating envelope is desirable for field operators to produce more continuously and economically from wells with very high gas content.
The Effect of Graphite on the Properties of Class G Oil Well Cement
Authors: Pratama Muhammad Andiva , Mahmoud Ahmed Abdulhamid , Elkatatny Salaheldin
Published: March 2023

Cementing process is one of the most crucial parts in drilling operation that could determine the durability and stability of the oil or gas well. Many additives had been introduced into the formula of the oil well cement to reach certain qualities to support the well. This study intends to analyze the effect of graphite on the properties of the hardened cement samples as a function of curing time, and compare the change in the properties with that for the samples prepared without graphite. The alteration in properties of the cement compressive strength, Poisson's ratio, Young's modulus, and permeability were studied with curing time. The results showed that the graphite successfully increased the compressive strength, and Poisson's ratio while Young's modulus was reduced which indicates an enhancement in cement strength and elasticity. The cement sheath permeability was also decreased indicating formation of more tight cement sheath with incorporation of graphite into the cement slurry.
Power of 6 Sigma to Overcome Chronic Business Pain Area
Authors: Albusafi Adil , Albalush Farah , Alshuily Mohammed , Albalushi Najim , Alrahali Maadh , Alhinai Ashraf , Alsahlani Ali , Alsalhi Houd , Alkiumi Yousuf , Ram Nayakam , Muhammed Jithin , Maghdari Somaya
Published: March 2023

Production reporting management in oil field has been one of business pain area, with a cumbersome manual allocation process, causing argument over the estimation of produced volumes. Main challenges identified were the inaccuracy of involved meters, multiple production reporting tools, reactive mode decision making, staff exposure during BS&W sampling and Tank dipping. Hence, tremendous integrated efforts using Six Sigma Green Belt Lean approach were made to simplify and sharpen the production reporting process, as well as minimizing the human factor in it.

This project undergone Six Sigma Green Belt Lean project approach as below:

Define stage: define project status, scope in/out, desired status, anticipated business benefits, …etc Measure stage: developed detailed "As Is" process pap identifying all critical X's and data collection plan Analysis stage: developed cause & effect and data graphical analysis (Scattered Plot, Matrix Plot, Box Plot, Dot Plot, Correlation, Regression) Improve stage: generate ideas for potential solutions & prioritization, failure mode & effects analysis show reduction of RPN and Pilot was run where X was optimized accordingly Control stage: developed control plan, standard Operating Procedure (SOP), Visual Management Board (VMB), Leader Standard Work (LSW) & To Be process map and reported business benefits Replicate stage: developed replication candidate alignment & plan

These efforts have resulted in a pronounced business benefit such as:

1.2% Oil Gain 5.7% deferment reduction Full Time Equivalent (FTE) saving of 2.69, which was wasted on various parts of the old methodology Process enhancement of production reporting and making data available which increased the confidence in production data Better focus on low-performing fields to identify surface and subsurface opportunities & bottlenecks Quick, simple & effective solution for operational standard procedure that improved system availability, production gain & team proactiveness Eliminating several high-risk activities by automation several process Early identification of leaks through new developed tools Flare Reduction by early identification of LCV failure and improving measurement system (automated)10% flaring reduction in field-x as result of fixing LCV failure Build the 1st PDO Live Production Management & Monitoring tool which is replicated in other four assets in Oil North Directorate with ongoing replication in the Oil South Directorate.

This innovative 1st PDO Live Production tool is a powerful utilization of the 6 Sigma deep data analysis to insure safe operations of the business processes through:

Optimize operational control systems to eliminate personal & process safety exposure Enhancement of system stability & reduction of trips and human interventions Operating Assets within approved Operating Envelope (OE)
Technical Challenges and Strategic Solutions for a New Historical Milestone: The Success of Delivering the First Two 10 K ft Lateral Wells in an Unconventional Drilling Operation
Authors: Yin Guoqiang , Almasmoom Salahaldeen , Ali Mohammad , Almalki Nawaf
Published: March 2023

To increase the reservoir contact to improve the production, the operator extended the lateral length of the horizontal wells from initial 5 K ft to 6 K ft, then to 7 K ft until 8 K ft. While moving toward a 10 K ft lateral, a bottle neck was encountered and the drilling team had to made all the effort to seek the solution. This paper addressed the main technical challenges to be faced while drilling the first two extended reach 10 K ft lateral wells. Several key strategic solutions corresponding to those challenges were proposed during the planning phase and well implemented in operation. As a result, the first two 10 K ft lateral wells were successfully drilled and completed, establishing a new historical milestone for future operation.

In this paper, the inefficient weight transfer while drilling because of the pipe buckling, wellbore instability, the severe losses of the weak formation, failure to build the curve and difficulties for the well placement in lateral, downhole tool directional tool failure due to the high bottom-hole-circulation-temperatures (BHCT) and the risk of unable to run the production casing to bottom were considered as the main challenges to deliver the 10 K ft lateral wells. To overcome these challenges, according to the established best practice and the available tools or devices that have been already tested and prepared, the drilling team performed profound analysis and established the corresponding strategic solutions for each challenge. This paper described the implementation process of those strategies on the first two 10 K ft lateral wells delivered. The experiences obtained were also addressed.
Artificial Well Engineering Intelligence (AweI): Is It Drilling Engineer's Dream or Driller's Nightmare?
Authors: Samuel Robello , Kumar Kiran
Published: March 2023

Applying artificial intelligence (AI) is exceedingly difficult for drilling operations as the system is overly complex and dynamic. As a result, more comprehensive domain-general engineering mapping, also known as "artificial well engineering intelligence," is required to predict operating parameters and problems with reasonable accuracy. This paper presents a detailed overview of engineering models that are interconnected in the form of microservices to provide a more logical solution as the well is drilled. It draws out some important findings and discusses ways that results can be infused with the work on explainable artificial engineering intelligence in realtime. The results argue the logical reasoning and mathematical proof.

Drilling Engineer–Driller–Rig system interaction through AweI with interconnected subdomains requires tighter integration between various engineering models. To some extent, tractable abstract knowledge at the human level is derived from analytical reasoning through engineering models. Various engineering models are connected in the form of microservices, which can be called any number of times when the optimization is carried out. The results are transferred for physical actions either to the driller or control as set points. The method presented does not claim to address all the issues as a whole. This methodology attempts, however, to present a coherent adaptive model that provides more transparency to the algorithms that can be used as operational parameters for the driller.

The analysis results have shown that the convergence was very quick in obtaining an optimal solution and the predictability in the test wells has shown the best solution results under uncertainty. It has also been found that the results provide reasonable threshold values when increased data is used as the well is drilled. As long as the driller stays within the operational region, the results have shown that the operating parameters are satisfying and good enough for the desirable outcome. In other words, a near-normal engineering solution is achieved.

The two major interacting bottlenecks observed in the study are (1) the absence of domain-expertise and mapping the conceptual space and (2) the valuation of the results, which can be translated into practical operational parameters.

The engineering microservices to derive engineering intelligence include the following: Torsional and lateral instabilities ROP coupled bit wear Hole cleaning Casing wear BHA Drill ahead Mechanical specific energy Hydro mechanical specific energy Motor stall weight (if motor present)
Complex Micro-Containers (CMC) Transporting Compartmentalized Reaction Mixture for Self-Healing Cement
Authors: Baltaeva Madina , Stamer Katerina , Orlov Maxim
Published: March 2023

Zonal isolation and cement sheath integrity are vital for a consistent oil and gas production process in an economic and environmentally conscious manner. However, cement is a brittle material that can fail under repeated application of stresses. The objective of this research is developing a novel material Complex micro-containers (CMC) to induce autonomous self-healing properties to the cement using the mechanism of a self-expanding polyurethane foam formation in a crack area.

Complex micro-containers (CMC) consist of polyol-loaded polyurea (PUa) micro- and nanocapsules loaded inside the isocyanate-filled core of larger polyurethane (PU) microcapsules. The method of CMC creation includes several steps. During the first step, an oil-in-oil emulsion, composed of organic solvent and polyol-polyamine solution, is created. The second step is made of a polyurea shell formation directly at the surface of the polyol droplets controlled by an addition of isocyanate. As the result of the interfacial polymerization process, micro- and nanocapsules are formed. Then, they are mixed with the isocyanate solution and further emulsified in the water-based media. The droplets of isocyanate with micro- and nanocapsules are encapsulated through polyurethane shell formation by adding polyol.

A variety of factors alter the morphology and size of the micro- and nanocapsules including parameters of emulsion's creation, core/shell ratio, and dispersion speed. The optimal content of isocyanate and polyols in cores of polyurea and polyurethane microcapsules, mechanical mixing parameters, and concentration of emulsifiers in oil-in-oil and oil-in-water emulsions were determined. FTIR-spectroscopy was used to identify the chemical structure and to demonstrate encapsulation of the isocyanate core and the polyurethane shell and the polyol core and polyurea shells. TGA-analysis, optical microscopy, and scanning electron microscopy methods were used to determine the core content of micro- and nanocapsules and their size. The peeling strength test proved that the release of the microcapsules’ core content occurs by pressure application and the diisocyanate reacts with polyol and water and creates the polyurethane material.

The main advantage of CMC is its expandable properties due to the formation of a polyurethane foam in the presence of water that can effectively fill the micro-cracks directly in a place of cement breakage. Integration of developed new material into the cement body will allow for improving a long-term wellbore isolation and mitigating a leakage potential in the cemented annuli.
Transforming a Mechanical Vertical Drilling Tool into a Digitally Controlled Rotary Steerable Tool - The Journey of Design, Development, Testing and Commercialization
Authors: Jones Steve , Sugiura Junichi
Published: March 2023

The design and development of a rotary steerable system from inception to commercialization, with proven performance/reliability recognition is an engineering challenge to say the least. Rotary steerable systems (RSS) are one of the most challenging drilling tools to bring successfully to the market. This is because they combine mechanics, electronics and hydraulics that all must operate together to make the system work.

With the complex task and cost of bringing multiple engineering disciplines together on one team (mechanical, electrical, electronic, embedded code, software and test engineers) to develop a rotary steerable, it is often a challenge for a small private company to start from the ground up. In this instance, a completely different approach was adopted to bring a unique RSS to the market.

Utilizing an existing mud operated mechanical vertical drilling tool with slow rotating steering head, the engineering team set to work to develop an electronic control unit with a digital mud valve to transform the tool into a cost-effective rotary steerable tool.

The design, development, engineering challenges, in-house and field-test program will be described to show how rotary steerable development on a budget is possible. Maintaining a tight project budget leads to engineering creativity and thought paths that cannot be inspired when large budgets are subsidizing product development.

The paper will detail how the rotary steerable product was successfully tested by partnering with operators in North America land. Selecting some of the harshest drilling areas for testing increased the pace of development, and improvement was accelerated with the use of multiple drilling dynamics sensors and pressure sensors.
Integration of Geosteering into an Automated Wellbore Placement System, Possibilities and Challenges
Authors: Holbrough David , Forshaw Matthew , Wessling Stefan , Idzerda Saskia , Gelfort Ralf , Austin Simon
Published: March 2023

The benefits of geosteering for accurate wellbore placement in reservoirs are well documented, with an emphasis on comprehensive reservoir mapping capabilities and related well path adjustments. Similarly, drilling-related processes such as well re-design, proximity scanning, and downlinking are important. The integration of geosteering and drilling processes adds complexity and challenges to designing automated wellbore placement systems. Automated systems need to contain sufficiently robust technologies and algorithms to avoid unintended and frequent exceptions. Equally, the human element must be considered to design an automated system with a great user experience. To gain user acceptance, an automated system must have the characteristics of predictability, transparency, adaptability, and automation levels that are validated prior to utilization. Without this, the result will be wellbore misplacement by engineers who blindly trust immature automated systems.

This paper provides an overview of processes and tasks within a comprehensive wellbore placement system, including the directional drilling and geosteering services as used by stakeholders who own well placement execution. We will provide an overview of the potential of automation and pitfalls to be avoided. The experience of many expert engineers from complementary disciplines has been used to develop a comprehensive concept as a framework to implement an automated wellbore placement system.

The paper also provides an analogy to the automotive industry which has developed reliable and robust systems for navigation, lane and speed control over the last few decades. The comparison highlights a fundamental difference to the petroleum industry of having multiple stakeholders involved in the process of wellbore placement. Consequently, communication between all the stakeholders during operations, notably proposals and approvals, must be designed into the system from the beginning.

Automation concepts to achieve great user experience are demonstrated on components of a wellbore placement process, including the illustration of lessons learned from recent development initiatives. Based on the demonstration, we conclude that an iterative development process is essential to ensure acceptance by the user community.
Rigless Repair of Packer Leak Via Annular Cement Plug
Authors: Yugay Andrey , Majed Ahmed Alkarbi Majed Ahmed , Berdiyev Yunus , Utama Indra , Al Hamadi Mohammed Thani , Hassan Karam , Al Marzooqui Afnan , Alshehhi Hajer Mohamed Ali J. , Rincon Gabriel , Al Menhali Shamsa , Ramadan Taha , Al Baloushi Mohammed Sayed , Elhanbouley Sheriff Hassan , Metlyaev Evgeny , Respati Indra , Eliatar Rabie , Setioko Enggal
Published: March 2023

Well double barrier envelope policy is a common industry practice and main philosophy of well integrity discipline. It is well-explained in well integrity related international standards: API RP90 (1 & 2), Norsok D10, ISO 16530 (1 & 2).

It states that all wells with positive pressure at surface capable to flow naturally should have primary and secondary barrier envelope. Primary barrier envelope consists of well equipment which is continuously in direct contact with hydrocarbon and is pressurized. In case primary barrier failure (leak through the tubing, packer, or other completion equipment element), secondary barrier envelope is the one that holds the pressure and prevents further escalation of the incident outside of well boundaries. The content of this paper is related to such kind of wells that comply to the double barrier policy and are equipped with production packers.

Conventional process of curing packer leak is to re-complete the well during rig intervention – the workover. During this process old completion is retrieved and new completion is installed. This operation can be repeated multiple times. Failure of any element of the primary barrier envelope results in the sustainable pressure in annulus "A" – SAP pressure. Such SAP wells is a violation from double well barrier policy and create a hazardous situation.
Performance Envelope of a High-Speed High-GVF Helico-Axial Pump
Authors: Ejim Chidirim , Xiao Jinjiang , Lee Woon , Zabala Wilson
Published: March 2023

Operating a pump at high speeds can have the benefit of increasing the capability of pumps to enhance surface or downhole production of fluids with high gas volume fraction (GVF). This study presents the performance envelope of a high-speed helico-axial pump (HAP) operating at high GVFs (> 80%). The ultimate aim of the physical tests was to ascertain the operating capabilities of the pump for potential scale-up to a field prototype.

The HAP housing outer diameter was 5.38-inch and operated at a rotational speed of 6000 revolutions per minute (RPM). Air and water were the test fluids, with average pump intake temperature of 25°C. The fluid volume flow rates were varied to maintain 50 psig at the HAP intake. The liquid and total intake volume flow rates varied from 128 to 664 barrels per day (BPD), and 4941 to 7593 BPD, respectively. The corresponding discharge pressures and temperatures, as well as electrical power input and current draw to the HAP motor, were also recorded.

The results showed that the HAP had stable operation during the tests for intake GVF range from 91% to 98%. The corresponding pump discharge pressures were in the range of 58 to 101 psig. This indicated the capability of the HAP to boost fluid pressure even for such high intake gas content. The results also showed that HAP boost pressure was positively correlated with liquid volume flow rates, and negatively correlated with the intake gas volume flow rates. Overall, the boost pressure decreased with intake GVF. The electrical input power to the HAP motor varied between 16 to 37 kW. It was observed to strongly increase with increasing liquid volume flow rate, and very strongly decrease with increasing HAP intake GVF. The associated electrical current draw by the HAP motor was seen to vary between 31 and 68 A. Its variation with liquid volume flow rate and intake GVF was similar to those of the electrical power input. In conclusion, the HAP demonstrated capability to boost fluid pressure when handling high GVF flows. It is being scaled up to a field prototype to handle higher volume flow rates of high GVF gas-liquid mixtures.

This study mainly highlights the method to extend the gas-handling capability of a HAP by operating it at high speeds. Optimal hydraulic design and proper conditioning of the inlet flow components were also incorporated in the HAP architecture. Expanding the HAP operating envelope to handle high-GVF flows significantly unlocks the potential for field operators to maximize hydrocarbon production from high-gas content applications. This, in turn, increases the economic bottom-line from the field asset.
High-Density High-Strength Phase Transforming Lost Circulation Material to Cure Severe to Total Losses in Reservoir and Non Reservoir Sections
Authors: Sarmah Pranjal
Published: March 2023

Lost circulation is one of the biggest expenses in terms of rig time and safety in oil and gas well drilling. Uncontrolled lost circulation can results a dangerous pressure control situation and loss of the well. Drilling through large natural fractures is a big challenge. This paper focus on developing high-density, high-strength, Fluid-Gel-Solid based lost circulation material (LCM) using novel surfactant with acid soluble sealant powder to cure the severe losses scenario.

Particulate material, polymer based system, cement, resin etc. has been used as lost circulation mitigation solutions but they have their own limitations of particle size, rheology, tolerance to contaminations, strength to cure sever to complete loss events. A novel fluid system is developed to mitigate these issues. Laboratory customization of the fluid has been evaluated with different temperature and pressure conditions. High pressure high temperature (HPHT) consistometer for setting time, rheometer for rheology and ultrasonic analyzer is used for measuring compressive strength. Tolerance to drilling fluids, spacer and cement contamination also evaluated. This acid soluble system has ease of cleaning if premature gelation occurs.

The fluid has thixotropic properties, viscous under static condition and shear thinning upon pumping, achieved through mixing of novel amphoteric surfactant along with water and sealant powder. This is a phase transforming fluid where amphoteric surfactant forms elongated worm-like micelle structure in presence of monovalent and/or divalent salts. Rheological study conducted to show the fluids elastic behavior and pumping property. This will help to assess the displacement of the LCM fluid. The sealant powder, working as weighting agent, sets hard with respect to temperature and time; and a setting control additive controls the hardening or setting process. Finally a high compressive strength solid plug is formed which can withstand the losses of fluids into the formation. Another added advantage of the system is – it can be optimized with seawater; fresh water is not a limitation.

The fluid technology is based on thixotropic-gelled using novel surfactant that resists the flow and loss of LCM fluid into the fractures once pumping is stopped. Tailor-made system with high-strength acid soluble sealant can be customized for low to high-density fluid formulations as per applications without any additional incremental treatment for seawater.
Investigation of Polymer Latex Effects on Cement Mechanical Properties for Improved Wellbore Integrity
Authors: Al-Yami Abdullah , Al-Qahtani Hussam , Nizar Jaber , Khan Majad , Nawaz Tahir Muhammad , Wagle Vikrant
Published: March 2023

Cement needs to be designed to prevent short-term and long-term gas migration scenarios. In the short term, the cement must prevent gas flow immediately following cement placement. In the long term, the cement must resist pressure and temperature cycling during drilling and production. Wells are subjected to substantial stresses from pressure and well testing, injection and stimulation treatments, thermal effects, production cycling, and changes in the surrounding formation over years. Due to these stresses, the cement sheath damage can occur during drilling, perforation and stimulation, and subsequent production. Polymer latex has been used to help reduce the fluid loss to minimize gas migration and aid in the mixing ability of cement slurries. However, there are some engineers who believe that polymer latex will improve cement mechanical properties.

The objective of this study is to evaluate the effect of polymer latex on cement mechanical properties after curing at elevated temperature and pressures. Experimental work in this study includes formulations at different polymer latex concentrations, densities measurements, rheology measurement, fluid loss testing, thickening time tests, curing for 30 days at elevated temperature and pressure, and finally mechanical properties measurements (Young's modulus, Poisson's ratio and compressive strength). The study shows that polymer latex will improve mechanical properties of cementing which will lead to improved wellbore integrity.
Expandable Resin for Countering Severe Loss Circulation
Authors: Wagle Vikrant , Ramasamy Jothibasu , Alanqari Khawlah , AlYami Abdullah
Published: March 2023

One of the main reasons why loss circulation is difficult to remedy is the lack of knowledge about accurate fracture width and depth encountered while drilling, leading to an improper selection of suitable plugging materials that can adapt, in both volume and shape, to effectively plug a wide range of fractures with unknown dimensions. Traditional, non-reactive particulate/fiber based or settable fluid, types of loss circulation materials (LCM), when applied in insufficient quantities, cannot effectively seal a high permeability zone. The LCM described in this paper is however expandable in nature. This expandable nature of the resin can help the LCM adapt in volume to effectively seal a wide range of fractures with unknown dimensions. Volume adaptability is introduced in the LCM through in-situ generation of gas due to the decomposition of a gas generating compound.

The novel expandable LCM comprises of a resinous material, a gas producing agent, surfactant and an activator. The resinous material in presence of a gas producing agent, surfactant and an activator is designed to expand under downhole conditions and help to cure severe losses. Different LCM compositions comprising varying concentrations of resin material, a gas producing agent, surfactant and an activator have been described in the paper. Two different resins were used in the study. The resins were mixed in different ratios and the impact on gelling time was investigated. An aliphatic chemical activator was used in the study. The effect of this activator on the gelation properties of the resin was investigated. The effect of temperature on the expansion of the resin in the presence of gas producing agent was also investigated.

The expandable LCM starts to generate gas in-situ under wellbore conditions. Laboratory testing has been performed to quantify the % of expansion of the resin at different temperatures. It was observed that the rate of gas generation is faster at higher temperatures. The expandable LCM is designed so as to have a controllable gelation time under a variety of downhole conditions to allow accurate placement of the LCM inside the wellbore without premature setting of the fluid. It was shown that the gelation time of the treatment composition could be controlled by adjusting the concentration of the activator. The system is designed so as to give a predictable and controllable pumping time, ranging from a few minutes to several hours at over a wide range of temperatures.
A Workflow to Assess the Effect of Lateral Landing, Completion, and Fracturing on Production Potential in an Explorational Clastic Environment
Authors: Herrera Carlos , Khan Abdul Muqtadir , Almulhim Abdulrahman , Hamid Saad
Published: March 2023

Three horizontal wells were drilled and completed with hydraulic fracturing in an explorational environment based on reservoir characterization from openhole logs. Limited success in establishing gas production rates showed the need for an integrated technical workflow to be applied for the next well, well-A. After good production results were achieved in well-A, the next phase used three more wells to correlate the production performance based on precise well placement.

In well-A, openhole sampling was done during drilling of the pilot hole prior to sidetracking the lateral. This was followed by a novel fracturing approach with slickwater hybrid, low-polymer, and CO2 foamed treatments to study the effectiveness of treatments. Post-fracturing diagnostics including a production log and spectral noise log (SNL) were performed to assess production by stage. Three more wells were drilled in the same reservoir, and then a synthetic correlation model was built with resistivity logs to correlate precise lateral landing with the prolific sublayer. Finally, the production performance of all wells was studied based on well placement, fracturing, and the completion approach.

The first phase of the study of the three wells allowed characterizing well-A in terms of reservoir interval, wellbore orientation, and fracturing strategy. Layer 1 was used to sidetrack the lateral. The post-fracturing production log and SNL indicated the CO2 foamed treatment was the best approach for well-A. The next three wells in the development phase were drilled in layer 1 with good production but inconsistent results. Because the highest flow rate in well-A was seen from the heel part of the lateral, an ultradeep resistivity-correlation bed boundary model was generated from well-A to characterize structural dip, and precise lateral locations were analyzed for all the wells. The model was also used to describe the most prolific sublayer within the layer 1 reservoir. The results showed a strong production dependence on the lateral landing with respect to the defined prolific sublayer. The number of fractures placed also showed a direct relation with gas rates. Finally, a geosteering simulation model was built to be used to further develop the area and detailed recommendations were documented. The ultradeep azimuthal resistivity tool has the capacity to detect ultradeep resistivity up to 100 ft from the borehole. Simultaneously, it can map ultrathin layers, which is necessary for the laminated reservoirs.

The objectives of precise well placement and rendering productive gas wells in the exploration area through a comprehensive workflow was optimized and analyzed over 4 years. This paper presents systematic findings and a robust framework ready for implementation in future developments.
Utilization of Innovative Resin-Cement Blend to Enhance Wellbore Integrity
Authors: Ali Wajid , Al-Turki Faisal Abdullah , Abbas Athman , Al-Yami Abdullah Saleh , Wagle Vikrant , Al-Safran Ali
Published: March 2023

A major challenge that is being occasionally faced during the well's lifecycle is the pressure buildup between the cemented casing annuli, also known as sustained casing pressure (SCP). Compromise of cement sheath integrity is one of the primary reasons for such a pressure buildup. This challenge prompted to develop such an isolation material that should enhance the mechanical properties of cement. The resin-cement blend system can be regarded as a novel technology to assure long term zonal isolation.

This paper presents the lab testing and application of the resin-cement system, where potential high-pressure influx was expected across a water-bearing formation. The resin-cement system was designed to be placed as a tail slurry to provide enhanced mechanical properties in comparison to a conventional slurry. The combined mixture of resin and cement slurry provided all the necessary properties of the desired product. The slurry was batch-mixed to ensure the homogeneity of resin-cement slurry mixture. The cement treatment was performed as designed and met all zonal isolation objectives.

Engineered solutions ultimately deliver the optimal asset value of the reservoir. During the last few decades, several laboratory investigations and field studies have been conducted to find solutions to the problem of SCP, which appears after primary or remedial cement jobs. Almost all these studies unanimously conclude that the conventional cement does not always endure the mechanical stresses imposed by the wellbore conditions and it often falls short in providing long term isolation beyond the production life of the well. When the resin is introduced into a cement slurry, it forms a dense, highly cross-linked matrix. The extent of the cross-linking reaction is governed primarily by volume, temperature, and time. The distribution of resin throughout the slurry provides a shock-absorbing tendency to the particulates of the cement. This feature increases the ductility and the resilience to withstand stress from load-inducing events throughout the life of the well. Resin-cement's increased compressive strength, ductility, and enhanced shear bond strength help to provide a dependable barrier that would help prevent future sustained casing pressure (SCP).
Improved Reservoir Management with Multi Positioning Interval Control Valves in Multilateral Wells
Authors: Shahreyar Noman , Butler Ben , Shakeel Muzzammil
Published: March 2023

Multilateral technology continues to gain interest within the oil and gas industry. While multilateral wells are recognized as an advanced well construction and completion technique to optimize production performance and improve field recovery, further opportunities exist to increase production performance throughout the life of these wells through the use of variable inflow control for the main bore and/or the laterals. The inflow control on these wells is achieved by interval control valves (ICV). An ICV is generally classified as either on-off (i.e., full-open or closed) or multi-position (i.e. discrete choking type). This paper discusses a reservoir simulation case study with varying degrees of inflow control to demonstrate value added by ICVs to multilateral completions to improve oil recovery of a field.

A 3D black-oil reservoir model was utilized to simulate production and cumulative recovery evaluation with horizontal and multilateral intelligent completion oil producers supported by vertical non-intelligent water injectors. The modeling was carried out with varying degrees of control in the ICVs employed in the oil producers. Multiple scenarios were modeled as follows: 2-position ICV (open-closed)4-position ICV (choking)9-position ICV (choking)

This modeling will quantify the value provided by a customized multi-position ICV in a multilateral intelligent completion with regards to improved reservoir performance. Since the customized ICV solution requires a more detailed well completion design and evaluation, it is necessary to be able to quantify the value that this option can deliver when employed in multilaterals. This paper shall demonstrate the added value that can be achieved in multilateral wells by utilizing multi-position choking ICVs versus binary open-close ICVs to manage reservoir uncertainty and improve reservoir performance. This paper will also highlight the importance of flow discharge characteristics with respect to each choking position and the benefits of flow trim customization during well life.
Unlocking Fracture Characterization Ambiguity a Multi Disciplinary Integrated Approach
Authors: Abughneej Ali , Al Naqeeb Mohamed , Al-Ostath Moahmmed , Albanay Fatemah , Abd El Dayem Muhammad , Al-Hamad Nasser , Al-Jamaan Abdullah , Akbar Laila
Published: March 2023

Fracture systems play a significant role in production in the case of tight/low porosity complex reservoirs. Exploration well in North Kuwait that targets Middle Marrat formation is met with the challenge of lack of understanding of reservoir compartments in an under-explored field, with minimum offset wells to properly evaluate its potential. A multi-domain approach is proposed with various expertise to tackle the petrophysical and geomechanical aspects of the fracture system governing the carbonate layer, to assess its producibility and its qualification for stimulation through hydraulic fracturing.

To address the exploration challenge, a novel comprehensive approach for fracture evaluation was implemented for the first time, starting at the wellbore stage, followed by an extensive analysis far away from the wellbore to evaluate their extent and their possible contribution to the flow, later combined with a geomechanical evaluation of their stress state, to come up with a confident estimation of their producibility and subsequently, a proper completion optimization plan for maximum reservoir exploitation.

The robust approach started with deployment of the image logs photorealistic oil-based mud imager with the purpose of capturing the highest resolution prospect of fractures on the borehole wall. The image logs tool provides direct quantification of fracture properties with regard to their density and orientation, and visual qualification of their type, connectedness, and aperture.

The 3D Far-Field Sonic technology was then implemented to unveil the ambiguity typically associated with fracture analysis, and provide new insight into the fracture continuity, reaching up to 160ft away from the borehole circumference which is a unique answer product presented for the first time in oil field market. The 3D Far-Field Sonic delivered astonishing results by identifying highly fractured zones and fracture extensions including the true dip and azimuth for each fracture. Geomechanical evaluation was carried out to understand the stress regime, and the relationship between critically stressed fractures with production patterns, and ultimately provide a location and direction to guide enhanced production in future wells.

Integrating data from various advanced tools helped identify zones of producing fractures and provided a practical solution for stimulation optimization. The multi-domain expertise addressed the challenge of natural fractures consistency between different measurements and allowed for proper evaluation of critically stressed fractures to understand production mechanisms and depletion behavior, through understanding present-day stress state, fracture geometry, and fracture slip properties. The consistency of the study provided convenient results ensuring proper well planning and future completion strategies.
Improved AMD Nanosheet System to Increase Oil Production Under Harsh Reservoir Conditions
Authors: Cao Dongqing , Han Ming , Fahmi Mohanad M. , AlSofi Abdulkareem M.
Published: March 2023

Amphiphilic molybdenum disulfide (AMD) nanosheet is a novel flake type Nano material, which is different from the widely used particulate Nano material, for increasing oil production. Most of the current researches and applications of nanosheets were for low temperature and low permeability sandstone reservoirs. This work investigated an improved nanosheet system for permeable carbonates at harsh reservoir conditions.

AMD nanosheet sample was a concentrated black liquid with flake size about 80*60*1.2 nm. The features in a high salinity water (HSW) and high temperature were characterized by compatibility test, interfacial tension (IFT) test, emulsification test, and phase behavior test. The potential for increasing oil production was evaluated by micromodel displacement tests. The micromodel was treated to oil-wet to simulate the wettability of carbonates. The performances of initial sample and improved sample by a cationic surfactant were compared.

Initial AMD nanosheet sample was not compatible with HSW at 95 °C. A cationic surfactant significantly improve the compatibility. IFT of 50 mg/L nanosheet with a light oil was 0.46 mN/m at 25 °C. IFT of The improved system with the surfactant decreased to 0.21 mN/m at 90 °C. The increase of nanosheet and surfactant concentration resulted in an IFT increase. Although IFT was not ultra-low, nanosheet had strong interfacial activity on oil-water interface even at low concentration. Nanosheet-only produced much stable emulsion than surfactant-only. Mixing nanosheet and surfactant increased emulsion stability slightly. Phase behavior results demonstrated that surfactant improved the hydrophilic and lipophilic balance of nanosheet to produce Winsor III type microemulsion. In core flow testing, the nanosheet alone injection partially plugged the core plug with relatively high adsorption/retention. Adding the surfactant improved the migration and reduced adsorption of nanosheet in porous media. Micromodel displacement test showed that improved nanosheet system at low concentration of 50 mg/L increased oil production by more than 20% after water flooding at both ambient temperature and reservoir temperature at 95 °C.

This study investigated a more efficient material with same dimension as oil-water interface compared with surfactant or particulate Nano materials. An improved nanosheet system was developed for carbonate reservoirs under harsh conditions.