bluuebunny/crossref_metadata_2025 huggingface dataset:
Superactive Surfactant for Enhanced Oil Recovery
Authors: AlRadhwan Azizah , Hamad Mohammed Al , Abdallah Wael
Published: March 2023

After primary and secondary oil recovery, a large amount of oil is left behind in the reservoir. Enhanced oil recovery (EOR) techniques are introduced to recover additional oil from the reservoir. Chemical EOR is one of the commonly used EOR techniques. It involves the use of chemical substances such as surfactants. Surfactants are commonly used in the petroleum industry because they have the ability to change the water-oil interface as well as the properties of the rock surface. The use of such surfactants depends on technical, financial, and environmental factors. In this study, the performance of a new superactive surfactant is evaluated for use as an oil recovery agent for carbonate and sandstone formations. The surfactant showed high stability in deionized water and seawater, with strong ability to lower the interfacial tension of different crude oils (light, medium, and heavy) at a very low concentration (i.e., 0.05 wt%). The maximum reduction in interfacial tension reached 99.5%. The surfactant also showed significant surface wettability alteration toward water-wet at the tested concentration, with maximum reduction of 87%. From the interfacial tension and wettability experiment results, the optimum system was obtained for the medium crude oil and seawater at surfactant concentration of 0.05 wt%. Therefore, the coreflooding experiments on carbonate and sandstone samples were carried out using this system. Results showed a significant additional oil recovery by the surfactant injection. Additional oil of 43% was recovered from the carbonate core samples, while 16% recovered from the sandstone sample. With these results, this new surfactant can be potentially considered as a new agent for enhancing oil recovery from carbonate and sandstone formations.
Novel Shear Dependent Cement Slurry System, Tailored to Rescue and Cure Losses when ECD Management and LCM Pills Failed – A Case Study from Southern Iraq.
Authors: Campana Barbosa Lucio Felipe , Iqbal Javaid
Published: March 2023

The southern oilfields of Iraq have primarily two rock formations that stand out regarding how to manage fluid losses. The two formations have fluid losses due to their natural vugular porosity in the intermediate section, and additionally, a production zone that presents losses while drilling, thus compromising the hydraulic isolation of the reservoir and validating a dependable barrier above the production zone. The average well profile in this region of the country has a hole size that is usually drilled across these formations of either 17 ½" or 12 ¼" for the first and second loss zones and 12 ¼" or 8 ½" for the third loss zone. This situation renders the conventional solutions to cure losses less likely since the treatment entails a massive quantity of materials to attain success, typically after one or two unsuccessful attempts. For three consecutive years, a thixotropic and acid-soluble cement-based lost circulation treatment shave been ranked as the preferred solution by the operators drilling in these fields. This solution can be pumped through the drilling BHA, it does not exhibit mixing complexities, it is acid soluble, and eventually develops tailored compressive strength which prevents an accidental sidetrack.

The stratigraphic column of Southern Iraq has within the first 2,500 meters of depth the Dammam, the Hartha, and the Mishrif formations, which are highly susceptible to lost circulation problems, and ineffective treatment can lead to an increased rig time and accidental sidetracks. This paper describes how this preferred treatment is effective and how to evaluate well conditions to select the treatment volume, explains the regular job execution procedure, and breaks down the key parameters that the treatment fluid needs to demonstrate to maximize the chances of curing losses in the first attempt, enabling rig time and cost savings based on the historical cases from jobs performed in the Zubair and Rumaila fields.
Scale-Up Fabrication and Microfluidic Evaluation of Janus Graphene Nanofluids as Novel EOR Agent
Authors: Wang Wei , Chang Sehoon , Thomas Gawain
Published: March 2023

Nanofluid flooding is an emerging enhanced oil recovery (EOR) technique whereby injection fluids containing nanoparticles or nanocomposites are utilized for the oil displacement or injectivity improvement in oil reservoirs. However, current nanofluids with conventional nanoparticles have relatively low efficiency for EOR at simulated reservoir conditions, especially at low concentrations of nanoparticles. This research reported a new cost-effective method for scale-up synthesis of Janus graphene nanosheets and demonstrated a new type of nanomaterials, Janus nanofluids, as highly effective alternative nano-agents for EOR applications. A lyotropic liquid crystal phase as a novel "interfacial nano-reactor" system has been developed for fabricating Janus nanomaterials at nano-scaled liquid-liquid interfaces. Compared to interfacial reaction in a conventional bi-phase system, the new "interfacial nano-reactors" could tremendously enlarge the interfacial area by more than million times for chemical reactions at the interface, and thus allow production of Janus nanomaterials in mass quantity economically for industrial applications. Janus graphene nanosheets synthesized via this method have been characterized and confirmed by multiple techniques including scanning electron microscopy (SEM), Langmuir-Blodgett (LB) isotherm, contact angle, and interfacial tension (IFT) measurements. Interfacial tension measurements have shown that the Janus graphene nanosheets could significantly lower the IFTs between brine and crude oil at simulated reservoir conditions. With low concentration of Janus graphene nanosheets in nanofluid formula, microfluidic flooding experiments have been performed to evaluate the efficiency of the nanofluids for oil displacement in carbonate reservoirs. The results have demonstrated improved efficiency of oil recovery by the novel Janus graphene nanofluids at ultra-low concentration (0.01 wt%).
Fracture Characterization and Modeling in Dual Media Systems and its Impact on Reservoir Connectivity and Well Productivity
Authors: Al Mulhim Abdulrahim K. , Alnasser Mohammed H. , Hamam Hassan H. , Maucec Marko
Published: March 2023

A successful field development plan relies heavily on comprehending various subsurface complexities and their impact on the petroleum system. Hence, reservoir modeling plays an essential role in aggregating the complex systems and incorporating uncertainties. In the past decades, fracture characterization and modeling has advanced significantly in providing a high-resolution depiction of the subsurface. This paper focused on examining the impact of major fractures on reservoir connectivity and well productivity.

Fracture modeling and parameterization were performed using a synthetic dual porosity, dual permeability (DPDP) simulation model that was based on SPE10 model. Various deterministic fracture realizations were generated by incorporating multiple scenarios of different features such as fractures, high-permeability and high-flow feature planes, and layer bound fractures. The positioning of major longitudinal and lateral fractures was examined to analyze their role on reservoir connectivity and well productivity. Special focus was devoted to evaluate the impact of limited vertical and horizontal fracture extensions compared to more conventional workflows where fractures are modeled as planes across the entire reservoir. Furthermore, additional operational conditions, such as variable water injection schemes and depletion strategies, were applied to assess their impact on the model's response.

The evaluation provided in-depth analysis of various subsurface flow scenarios with DPDP systems. The characterization and modeling of complex subsurface features enhanced the understanding of spatial flow dynamics and their impact on reservoir performance. For example, layer-bound fractures result in different dynamic behavior compared to the ones crossing the entire reservoir. Additionally, high-flow features like high permeability streaks alter subsurface flow dynamics by accelerating fluid movement. Therefore, production analysis was performed for every scenario independently to benchmark the impact of various fracture parameters.

The paper provides comprehensive evaluation of fracture parameterization on subsurface dynamics by utilizing a DPDP SPE10 model to determine the distinct fracture signatures of reservoir performance and their influence on the overall hydrocarbon recovery.
Zero Losses Implementing a Heavyweight Engineered Spacer While Cementing a Rotatable V0 Expandable LinerHanger
Authors: Contreras Nino Adriana , Alabbad Mahmoud , De La Cruz Alejandro , Hugentobler Kory
Published: March 2023

The high-pressure/high-temperature (HPHT) environment poses different challenges for a cement design. In addition, there are challenges with the tight annular clearances across the liner overlap with the previous casing, and then finally achieving the desired top of cement. Engineering solutions and best practices can be implemented to overcome the challenges encountered while cementing under these conditions. A heavyweight engineered spacer with loss circulation material and an expandable-rotatable liner hanger were key components of the success.

Thoughtful analysis of the equivalent circulating density (ECD) resulted in the design of the train of fluids with a density difference of no more than 0.5 ppg. However, to overcome the risk of losses, an engineered spacer with a tailored load of its main component based on extensive lab testing was used. The weighting agent was carefully selected to ensure stability and rheological hierarchy. The cement job was performed with backside pressure applied with Managed Pressure Cementing (MPC) to keep a constant downhole pressure. To improve displacement efficiency and enhance cement bonding, an expandable liner hanger was rotated throughout the entire job and set afterwards.

The best practices implemented to cement the 9 5/8in liner resulted in performing the cement job without losses or flow. The ECD was kept within 5% from the mud weight density, based on the pressure match simulation. No abnormal pressures were observed while pumping and displacing indicating no settling issues were endured with the engineered spacer. Additionally, the liner hanger's unrestricted bypass area assisted in reducing the ECD's as no slips were required to keep it in place. The liner hanger was successfully rotated at 15 rpm throughout the job providing good cement placement. After the cementing job, the Liner hanger expanded successfully which confirmed the liner top integrity with a metal-to-metal seal. The expandable liner hanger also allows for less leak paths in the system along with providing high sealing and loading capability in high temperatures with a gas tight seal rating. After the wait on cement (WOC) time, the positive and negative tests were performed successfully meaning that a sustainable barrier was achieved.

This paper describes a success story while cementing under HPHT conditions with very narrow margins between pore pressure and fracture gradient and depicts the best practices that contributed to the success of the job, such as using a heavyweight engineered spacer with LCM and an expandable/rotatable liner.
Synergistic Hydrate Inhibition by Iota-Carrageenan with Kinetic Hydrate Inhibitors
Authors: Suri Ajay , Singh Ankur
Published: March 2023

The hydrate-inhibiting performance of a natural plant-based polysaccharide iota-carrageenan is evaluated as a standalone inhibitor and as a synergist with two well-known kinetic hydrate inhibitors (KHIs), polyvinyl caprolactam (PVCap) and polyvinylpyrrolidone (PVP), in order to achieve a higher hydrate inhibition performance. The hydrate inhibiting performance is assessed experimentally by measuring the induction time (IT) required for measurable hydrate formation and by the average hydrate growth rate (HGR) after measurable hydrate formation using a standard constant cooling rate of 1°C/h. Three inhibitor dosages at 0.5 wt% and 1 wt% are tested for the methane hydrate formation at 7.6 MPa and hydrate equilibrium temperature of 10.45°C. Synergy evaluation between the common KHIs and iota-carrageenan is done by making 50:50 ratio blends of iota-carrageenan with PVP and PVCap respectively (half iota-carrageenan and half KHI by wt%) and their performance is compared with the performance of individual PVP and PVCap performance at the same total inhibitor concentration for fair comparison. The individual inhibitor experimental results at 0.5-1 wt% showed that iota-carrageenan has a lower IT (around 4.5-5 h) than PVP (around 5.5-6.3 h) and PVCap (around 6.5-7.1 h), but has a lower average hydrate growth rate (HGR) between 0.07-0.08 m/h compared to PVCap (0.11-0.12 m/h) and PVP (0.13-0.18 m/h). The experimental results for the 50:50 blends of i-crgn with PVP and PVCap at a total concentration of 0.5-1 wt%, showed significant boost in the ITs (8.1-10.2 h for PVP and i-crgn blend) and (8.7-11.2 h for PVCap and i-crgn blend). These values were up 33-57% at the same total concentration of the individual inhibitor and the blend. The blends also have a much lower HGR with values 0.04-0.12 m/h at a total concentration of 0.5-1 wt% which is 16 - 64% lower than the individual HGRs of PVP and PVCap. Hence, iota-carrageenan, a natural, non-toxic, sustainable chemical can be used as hydrate inhibiting synergist additive to PVP and PVCap and other commercial hydrate inhibitors for enhanced hydrate inhibition performance and biodegradability.
Graph-Based Temporal Process Planning and Scheduling for Well Drilling Operations
Authors: Pavlov Maksimilian , Bukhanov Nikita , Safonov Sergey
Published: March 2023

Well construction is the most expensive stage of oil field development. Oil and gas companies carefully calculate all possible expenditures to assure that the project of well construction and exploitation will be profitable in time. The time for every operation of well construction is strictly regulated. However, in different oil and gas companies time allotted, for example, cementing surface casing or tripping operations can differ significantly. Therefore, some oil and gas companies are unable to calculate their well construction expenses accurately and lose a significant amount of money, which can be reduced. Also, engineering teams spend a substantial amount of time developing a drilling plan for the drilling crew, which may also be fully or partially developed by automated means. We present a data-driven approach for automatic planning and scheduling of drilling operations on wells with similar design and geological characteristics, suggesting also an improved operation classification based on the IADC dictionary of drilling operations.

The model for drilling operations planning is based on the directed graph traversal and process mining techniques. The algorithm takes as an input an undetailed plan, the section which is planned to be drilled, and the phase of well construction (drilling, cementing, logging). The algorithm selects the shortest path between two adjacent operations, gathers all paths together, and outputs a detailed plan with the corresponding time for each operation. For directed graph construction, we processed about 15 drilling reports from wells of a particular oil field which have similar well design and geology conditions by virtue of their geological proximity.

Algorithm performance was estimated by comparing graph time against similar plan time which was calculated based on the median time of every operation in a whole dataset. Median time (P50 percentile) was used because it demonstrates objective time in terms of well construction operations. We conjecture the above based on the fact that in some cases time for tripping can be faster or slower in some wells due to geological or other conditions, and the median provides an outlier-robust estimate of the average value. Also, graph time was compared between the engineering team's proposed plan and the actual time from drilling reports. Graph construction quality was estimated using three principal metrics: the Jaccard coefficient, structural distance, and fitness similarity.
All Metal Wellbore Intervention Tools as an Alternative to Motors
Authors: Pearson Allan , Luchak Mark , Curle Robert
Published: March 2023

Step-changes made by the development of a hydraulic casing reamer shoe built to land casing in problematic wellbores has now led to the development of a serviceable all-metal wellbore intervention tool. By employing a similar all-metal drive system as the casing deployment HSRT: Hi-Speed Reaming Tool into thru-tubing sizes, these compact, retrievable and serviceable tools are being deployed effectively in harsh environments. Cost-effectiveness and ease of service make the TT-HSRT: Thru Tubing Hi-Speed Reaming Tool an ideal alternative to downhole motors in certain intervention applications. TT-HSRT's can be deployed in harsh high temperature environments (250°C / 482°F) and are compatible with acids, solvents and nitrogen required in various wellbore stimulations. Those conditions are quite detrimental and costly to a standard elastomer power section in a positive displacement motor. Another advantage the TT-HSRT has over a motor is a much shorter bottom-hole assembly (BHA) length and ease of serviceability.

Current industry offerings do not provide the RPM range, the custom wash head configurations, or compatibility with third party milling-style heads. The original casing-deployment high speed reaming tools were designed with drillable all metal internals to aid in effective casing landing; in the thru-tubing version the proprietary internal drive system was scaled down to create a serviceable and retrievable tool to be used in jetting, descaling, stimulations, and other various casing and thru tubing interventions. The thru-tubing HSRT design uses industry-standard pin or box down connections, allowing the option to use third party wash heads and milling style heads which can be quickly changed in the field.

This technology provides workover engineers with a low-cost optimization option for wellbore interventions, with the ability to complete multiple operations in a single run. This translates to valuable time savings as well as cost savings on repair and maintenance. Another major benefit is the internal drive system which has proven to be very reliable.

Three thru-tubing sizes are available and are all under one meter in length. The tools contain zero elastomer or o-ring seals. The high RPM and low torque drive system give the tool a strong cost-saving advantage over traditional ‘elastomer and coated rotor’ style power sections found in downhole motors, particularly where a high torque requirement is not needed to complete the work.

This paper will outline the development of this technology versus a positive displacement downhole motor and include international and domestic case histories outlining the tools’ use.
Down Hole Data Driven Optimization on Bit, Parameters and BHA Lead to an Outstanding Performance in Deep Gas Drilling
Authors: Kouzaiha Rami , Cleboski Christopher , Vrnak Kyle , Daechsel Dustin , Al Rawahi Nadir
Published: March 2023

Deep gas drilling the early Devonian unconformity in Oman is an extremely challenging hard and abrasive application fraught with a diverse set of PDC drill bit challenges and objectives, particularly in the 8 3/8″ vertical section where between 2 to 4 fixed cutter drill bits can be necessary to reach total depth. Each trip can significantly impact well construction cost and delay production on stream dates. Using high frequency digital data collected at the drill bit and detailed forensic analysis of drill bit photographs a new, physics based, drilling equipment and parameter strategy was developed.

The section requires drilling approximately 2,000m of hard and abrasive interbedded Sandstone and Shale formations to around 5,000m vertical depth. Drilling performance is typically limited by severe wear to the PDC cutting structure or motor failure from significant torsional and lateral vibrations. High frequency digital data was captured at the bit in conjunction with output data from an automated photometric dull grading system over several wells to identify dysfunction type. The results were then analyzed by vendor and operator SMEs collaboratively to optimize drilling parameter performance and provide insights into optimal cutter shape and grade selection to further reduce drilling dysfunction.

Using downhole high frequency digital readings to understand down hole vibrations and the impact of formation interaction on bit dull has led to changes in the cutting structure and the applied drilling strategy. Different drilling approaches were applied to each formation layer to manage interbedded transitions as well as to increase depth of cut for improved drill bit dynamic stability. Insights were derived from an automated dull grading system assisted in optimizing cutter shape and grade selection in the select parts of the drill bit cutting structure. The photometric analysis also helped refine drilling parameters for a more efficient drilling by increasing axial loading on hard formations that then resulted in increased ROP. Additionally, newly developed high abrasion resistant cutters placed optimally in the drill bit at the highest work locations based on automated dull grading feedback resulted in extended cutter life helping to keep the bit sharp and maintain the high rate of penetration through the various layers reaching final section depth with consistently high rate of penetration.

The execution of the new physics-based drilling strategy has resulted in improved bit dull grade conditions which helped reaching the section final depth in one run with reduced downhole dysfunctions. that resulted in a section drilled without trips and with reduced well construction costs. The section is 32% faster than the offsets and was drilled 7 days earlier compared to plan.
Comparison of Zirconia Nanoparticles with Conventionally Used Silica Nanoparticles for HTHP Drilling Applications
Authors: Ahmad Hafiz Mudaser , Iqbal Tanveer , Yaseen Saima , AlNabbat Yousif Yagoob , Murtaza Mobeen , Mahmoud Mohamed , Patil Shirish , Kamal Muhammad Shahzad
Published: March 2023

Well-designed formulations of drilling fluids are required for drilling operations to improve rheological and filtration properties. The rheological properties and fluid loss during the drilling process are severely affected at the deep well with high temperature and pressure conditions. This study investigates the comparison of zirconia nanoparticles and conventionally used silica nanoparticles on rheological and filtration properties at temperatures ranging from 76°F to 122°F. Sodium-bentonite dispersion in deionized water was used as the base drilling fluid.

Rheological properties were determined at different temperatures using a Discovery Hybrid rheometer with various concentrations of nanoparticles from 0.2 wt.% to 0.75 wt.% concentrations. Steady shear rheology experiments were performed to study drilling formulations’ shear stress, viscosity, and yield stress. Temperature ramp rheology tests at 76°F and 122°F were performed to analyze the effect of increasing temperature on viscosity. The filtration tests were conducted to study the fluid loss properties of drilling fluids at various concentrations of nanoparticles. Linear swelling analysis of clay in the presence of drilling muds was performed to study the shale inhibition properties of prepared drilling formulations.

The incorporation of nanoparticles significantly enhanced the rheological properties such as yield stress and viscosity at various concentrations and temperatures. Rheological properties of zirconia muds compared with silica muds for various concentrations of nanoparticles. Temperature ramp rheology tests showed that zirconia muds have enhanced viscosity at 0.75 wt.% compared to the counterpart of silica mud. A decrease in fluid loss was observed for zirconia muds compared to the base mud while fluid loss increases with increasing concentration of silica nanoparticles. The incorporation of nanoparticles in the drilling fluids significantly reduced the swelling of clay compared to the swelling of clay in deionized water.

This research supports the extensive interpretation of water-based drilling fluids using zirconia nanoparticles and a comparison of drilling properties with silica-based fluids for high-temperature applications. The potential use of zirconia nanoparticles in drilling fluid formulations provides the way forward for the improvement of fluid loss characteristics, shale inhibition, and rheological properties.
Viscometer Readings Prediction of Flat Rheology Drilling Fluids Using Adaptive Neuro-Fuzzy Inference System
Authors: Abdelaal Ahmed , Elkatatny Salaheldin , Ibrahim Ahmed
Published: March 2023

Flat rheology drilling fluids are synthetic-based fluids designed to provide better drilling performance with flat rheological properties for deep water and/or cold environments. The detailed mud properties are mainly measured in laboratories and are often measured twice a day in the field. This prevents real-time mud performance optimization and negatively affects the decisions. If the real-time estimation of mud properties, which affects decision-making in time, is absent, the ROP may slow down, and serious drilling problems and severe economic losses may take place. Consequently, it is important to evaluate the mud properties while drilling to capture the dynamics of mudflow. Unlike other mud properties, mud density (MD) and Marsh funnel viscosity (MFV) are frequently measured every 15–20 minutes in the field. The objective of this study is to predict the viscometer readings at 300 and 600 RPM (R600 and R300) of the flat rheology mud in real-time using machine learning (ML) and then calculate the other rheological properties using the existing equations. The developed model using adaptive neuro-fuzzy inference system (ANFIS) predicted the viscometer readings with an acceptable accuracy. The maximum average absolute percentage error (AAPE) was less than 7 % and the correlation coefficient (R) was more than 0.96 for training, testing and validation.
The Industry's First Real-Time Pseudo Gamma Measurements From an Instrumented Steerable Motor Using High-Frequency Drilling Dynamics Sensors
Authors: Sugiura Junichi , Jones Steve
Published: March 2023

Downhole drilling motors are the workhorse of our industry and are used on almost every land well drilled globally. This makes an instrumented drilling motor the perfect tool for geosteering with near-bit inclination, drilling-dynamics and formation-identification sensors. Already proven drilling motor technology has been upgraded with miniature embedded sensors to provide real-time continuous inclination, advanced drilling dynamics, and pseudo-formation-identification data. The sensors are sized to mount into existing drilling motor components without adding length or compromising the mechanical integrity.

The high-frequency drilling-dynamics measurements, including lateral vibrations, axial vibrations, stick-slip, high-frequency torsional oscillation (HFTO) and motor back-drive dynamics are measured in the motor. The sensor unit applies advanced signal processing routines to the high-frequency vibration measurements downhole and converts the vibration data into pseudo gamma (pGamma) measurements, which have been correlated with measurement-while-drilling (MWD) gamma measurements in lateral wellbores. pGamma can alert the driller as soon as the bit starts cutting new formations, as compared with traditional real-time gamma measurement, which is about 40-50ft away from the drill bit. In addition, the sensor units measure bit and string rotation speeds below and above the mud motor, enabling the detection of the motor output rotation speed and motor back-drive dynamics in real time.

Real-time near-bit inclination, advanced drilling-dynamics and geosteering measurements have been provided in a mud motor without compromising mechanical integrity or directional response. The real-time inclination, drilling dynamics data, and pseudo-gamma measurements from the instrumented motor are integrated into our drilling advisory system to enhance the drilling efficiency and wellbore placement accuracy.
Initiate Best Practice through Brilliant Planning and Executing of Drilling Level I Multilateral Horizontal Well in Kuwait to Accomplish Cost Optimization & Land Space Utilization
Authors: AL-Hajri Nasser , Al-Khaldy Ali , Hassan Jassim , Boukhamseen Ali , Dashti Reham , Alotaibi Fahad , Gupta Satya , Chawla Deepanshu
Published: March 2023

Reduced land slots availability for drilling of new wells, operator's focus to increase production, aim to reduce effective cost per barrel and to minimize the environmental footprint, worldwide drilling contractors/operators are looking for various solutions available to address these concerns.

Drilling multilateral wells is one of the solutions to these concerns.

This paper presents the process and steps followed in planning and decision making for drilling a multilateral well in one of the North field in Kuwait, which includes

Identification of filed and understanding formation, Categories of multilateral wells and selection of level and types of multilateral well, Pre requisition of data for level 1 multilateral well, Selection of well slot and reviewing additional tools/service requirement, Selection of well trajectories for multilateral well, Selection of open hole junction point, Selection of section TDs, Review of directional BHA & its suitability for open hole side track, Well control scenarios, Well stimulation plans, Review of Coil tubing (CTU) operation for stimulation and tools requirement, Contingencies plan for reservoir section, Cost saving, higher production, environmental footprint, well completion days.
A Geopolymer System for High Pressure Oil and Gas Well Cementing
Authors: Abdelaal Ahmed , Elkatatny Salaheldin , Abdel Fattah Ahmed
Published: March 2023

There are some technical and environmental issues associated with the usage of ordinary Portland cement (OPC) in well cementing. These concerns persuaded the researchers to search for alternative materials to overcome the technical challenges and to provide eco-friendly cement systems. The use of geopolymer technology is widespread across many industries, particularly the construction sector. Oil and gas well cementing hasn't yet seen a full-scale deployment of it, though. This work evaluates the possibility of using hematite to develop a heavy weight geopolymer system for cementing operations. The biggest challenge in this work was developing a flowable heavy weight geopolymer formulation with good rheological properties and sufficient thickening time. The evaluation included rheological properties, fluid filtrate, strength, petrophysical and dynamic elastic properties for the developed class F fly ash (FFA) hematite-based geopolymer formulation. The results showed that the developed high density geopolymer system possessed acceptable properties making it a possible candidate for different cementing applications.
Combining Nuclear Magnetic Resonance with Deep and Ultradeep Azimuthal Resistivity Images in Carbonate Reservoirs Links Reservoir Structure with Rock Type while Drilling
Authors: Ramadan Osama , Idris Umar , Van Steene Marie , Santoso Gagok
Published: March 2023

Deep and ultradeep azimuthal resistivity images enable precise well placement inside the reservoir structure. However, they deliver limited information about the quality of the reservoir, especially in carbonates, where large pore-size variations are common. Combining the deep and ultra-deep resistivity images with logging-while-drilling (LWD) nuclear magnetic resonance (NMR) measurements enables linking reservoir structure with rock types while drilling for optimal well placement.

The NMR data is used to generate four petrophysical rock types while drilling: RT-1 has good porosity and long T2 components, indicating large pores; RT-2 has good porosity but medium T2 components, indicating smaller pores; RT-3 has medium porosity and long T2 components; and RT-4 has medium or low porosity and medium or short T2 components, indicating the worst facies. The first step in identifying these rock types is running factor analysis on the NMR data. This data analysis method is used to reduce a large dataset to a smaller number of underlying components. Used with NMR data, the method typically produces 9 to 11 factors and their associated poro-fluid facies, which are further reduced to four to ease interpretation.

The method was implemented in two wells. The first had a single lateral, which was geosteered using ultradeep azimuthal resistivity images and NMR. The borehole entered the reservoir from the bottom. The NMR indicated a large section of RT-4, so the well was steered to cross into the upper reservoir lobe in search of better rock type. The best rock type, RT-2, was discovered at 8 ft true vertical depth (TVD) below the top of the reservoir, and geosteering continued within that rock type.

The second well was a trilateral, geosteered with deep azimuthal resistivity imaging and NMR measurements. The initial lateral penetrated the first reservoir layer, where the NMR indicated RT-3 rock type with high permeability. After about 500 ft of drilling, the target reservoir layer was identified below the wellbore, and the well was steered into it. The NMR initially indicated that the rock type was RT-2, but combining the reservoir structure from the deep azimuthal resistivity image inversion with NMR rock typing confirmed that the upper section of the second layer had the best rock type, namely RT-1. Based on this finding, the second and third laterals were placed in the upper part of the same reservoir layer, with an excellent net-to-gross ratio.

Association of NMR rock typing and reservoir structure while drilling is a new methodology that combines the strengths of both techniques to optimize reservoir understanding and well placement.
Successful Introduction of a Novel, High Dogleg Rotary Steerable System
Authors: Sutherland George , Lasater Jeff , Althoff Gary , Verma Jaywant
Published: March 2023

Rotary Steerable Systems (RSS's) have proven beneficial over conventional steerable motor systems, which has driven significant market uptake over the last several decades. Consequently, applications for RSS's have expanded and encouraged RSS technology developers to meet these ever-changing market demands. Modifications to the basic proven RSS methods, attempted independent reproductions of those methods, and other novel methods have emerged to fulfill these market demands.

The initial RSS method and technique were invented and proven in the late 1990s, and common ways of creating wellbore deflection emerged, allowing the industry to attempt the classification of these methods. These classifications were an attempt to gain a better understanding of the advantages and disadvantages of each and help understand where and what version of technology to apply for an ever-increasing expansion of applications.

This paper describes the attempts at classification of RSS's, then addresses the drivers, development, and field trial results of a new method for placing wells using a high dogleg automated rotary steering system (SwR; Steering-while-Rotating).

The SwR was targeted to meet market changes identified in 2016 and projected out ten (10) years by the SwR technical team. Simplicity, fostering reliability and value were major design tenets. A high dogleg curve (20°/100’) design, enabling "one-run, Vertical, Curve, and Lateral" bottom hole assemblies, two-way (uplink-downlink) downhole communications along with autonomous self-steering capability, also drove the SwR development.

The initial SwR prototype system for 8-3/8"-9-7/8" hole sizes was built, and field trials began in Q3 of 2019. The SwR team weathered the global Covid-19 pandemic of 2020-21 with the rest of the world and deployed systems to the Middle East, while also securing and executing trial and commercial runs within North America in 2021 and 2022. Conclusions are based upon, and data is presented from thirty-seven (37) bit runs and the first 50,000 feet drilled with the SwR.

The SwR team has delivered a unique steering method to the industry and presents the early run data demonstrating the SwR technology capability to drill challenging well profiles, in challenging environments. The SwR technology was designed for the RSS market of today and for several years to come improving the value proposition for modern RSS well placement technology.
An Integrative Software Platform to Support Drilling Operations in Troublesome Formations
Authors: Han Yanhui , Liu Chao , Phan Dung
Published: March 2023

A software product, called SAGE-WSA, has been developed to provide an integrative platform for experimenting impacts of various affecting factors and mechanisms on the drilling mud design and wellbore stability. The software packages analytical solutions of stresses, pore pressure, temperature, and chemical potentials around wellbore in both intact and fractured poroelastic media, and many failure criteria, including all often-used ones and some developed in-house. The software provides a friendly user interface for accepting inputs required for the well stability analysis and presenting computed results, such as mud weight window, failure region, stress distribution, etc., in form of charts, contour and spreadsheet. The application and performance of SAGE-WSA is demonstrated through calculating safe mud weight windows for drilling a few troublesome formations. In the low-permeability formations, the timescale of fluid diffusion around borehole is in the same order as drilling operation so the safe mud weight window is time-dependent. Computation shows that the critical mud weight calculated by SAGE-WSA converges to well-known Hubbert-Willis (H-W) solution for impermeable borehole at short time and Haimson-Fairhurst (H-F) solution for permeable borehole at large time. In high-pressure high-temperature formation, the time-dependent pressure diffusion and thermal diffusion are coupled. It is observed that the critical mud weight window is overestimated without considering cooling effect, which may cause formation permeability damage. In chemically active shales, the trouble comes from the chemical activity difference between drilling mud and the formation. In the analysis the poroelastic and chemical effects are coupled. For mud with lower activity, the water will be driven out of the formation and the pore pressure can be dropped significantly. In naturally fractured formations, the natural fractures speed up the diffusion process and degrade the mechanical strength, causing the safe mud weight window much narrower.
Minimizing Drill-String-Induced Wellbore Instability
Authors: Das Soukat Kumar , Albahrani Hussain , Bathija Arpita Pal , Finkbeiner Thomas
Published: March 2023

Objective/Scope

Every year the petroleum industry spends more than an estimated $6 billion in mitigating wellbore instabilities that account for nearly half of the drilling-related NPT (non-productive time). Researchers believe wellbore instability problems occur primarily due to physical and chemical interactions between rocks and drilling fluid and mostly neglect the impact of drill string vibrations on wellbore stability. However, such vibrations can cause significant damage to the formation, which then degrades the formation's mechanical integrity and compound wellbore instabilities. An appreciable body of evidence exists documenting that higher RPM (revolutions per minute), higher WOB (weight on bit), and pendulum BHA (bottom hole assembly) can cause enhanced agitation of the wellbore wall rock which may result in formation damage – often accompanied with an increased ROP (rate of penetration). The primary objective of this work is to review the state of modelling vibrations as documented in the literature and then advance the development and impact of vibrations and rock failure due to the aforementioned drilling parameters using numerical methods.

Methods, Procedures, Process

The proposed research will analyze the complex dynamic interaction between drill-string and borehole using a commercially available finite element package (e.g., COMSOL or ABAQUS etc.). These packages have the capability to create multiphysics-based models and simulate engineering and industry applications. A drill-string borehole assembly will be modelled with geometric and associated environmental and material boundary conditions (e.g., stress state, pore-fluid pressure, mud pressure etc.). The results will then be calibrated with experimental and field data.

Results, Observations, Conclusions

Subsurface drilling parameters are often undetermined or not measurable during drilling. The proposed model will aim at developing a drill-string-dynamics model to simulate the interactions between the wellbore and the drill string. This includes (i) estimation of drill string vibrations for different drill string and BHA designs, (ii) the resulting impact forces from drill string vibrations for different wellbore designs, and (iii) the influence of the estimated impact forces on the wellbore wall of particular (chosen) rock types at its current stress or yielding state.

Novel/Additive information

The research project proposed herein will equip the well-planning engineers with advanced and robust tools to predict and mitigate wellbore instabilities resulting from drill-string vibrations. We develop new models that incorporate the dynamics mentioned above in order to evaluate quantitatively the effects of drill string vibrations on wellbore instabilities.

We anticipate contributions along the following themes:
Laboratory Study on the Efficiency of Polymer-Based Foamed Gel for Conformance Control in High Temperature Reservoirs
Authors: Almulhim Noorah , Alarawi Abeer
Published: March 2023

Undesired water production is the most common problem of most oil and gas wells. Oil and gas production may be restricted because of high producing fluid levels commonly associated with high water production. In 2000, Bailey et al. reported that 3 barrels of water were produced for each barrel of oil, amounting to about 75 billion barrels of water at that time. The economic lives of many wells are shortened because of the excessive production cost associated with water production. These expenses include lifting, handling, separating, and disposing of an estimated $40 billion. The need to shut off unwanted water production is common to the entire well's life cycle spectrum. This research article presents the results of a series of experiments to evaluate the foamed gel characteristics, including foamability, thermal stability, and rheology at 77-150 °F.

The characteristics of developed polymer-based foamed gel formulas were investigated. The components of foamed gel formula were compatible with each other since there were no physical changes nor separation visually observed at 77-150°F. The half-life-time of polymer-based foam was 4 hours, 2 and 5 days for the base, 45 gpt and double concentrations of formulas at 77-150°F. The foamed fluid formulas were thermally stable at temperatures range of 77-150°F. Increasing the concentration of polymer-based agents in the formula led to enhancing the foamed gel's thermal stability to reach 7 days for the base, 45 gpt and double concentrations at 77°F, respectively.

In contrast, the gelling time of foamed gel was decreased with increasing the concentration of polymerbased agents in the formula. It was thirty minutes for base and one minute for 45 gpt and double concentrations at 77°F. In addition, a viscometer instrument was utilized to investigate the influence of doubled polymer-based agent's concentration on the apparent viscosity of foamed gel at 77- 150°F for three hours of measuring time. The apparent viscosity of foamed gel for the based concentration was at 75°F 30 Cp and it rapidly drop at 150°F immediately. For 45 gpt and double concentrations formulas the apparent viscosity were 2500 and 7000 cP for 45 gpt and double concentrations at 150°F and three hours of measuring time, respectively. Both of the second the third system with high concentration of polymerbased additives systems demonstrate viscosity higher than 2000 cp a strong-foamed gel formula for water shutoff application.

These results indicated that the doubled concentration of polymer-based agents is an optimum at temperatures of 77-150 °F. This work's novelty is developing an environmentally friendly, low-cost foamed gel recipe with only three additives. The prepared polymer-based-foamed gels can efficiently block different watercourses of high permeable zones at temperatures 77- 150°F. In addition, the gelling time can be easily controlled by altering the polymer-based agent's concentration.
A Novel Engineered Drilling Solution using a Sourceless Geosteering Bottomhole Assembly to Deliver the Longest Extended-Reach Well in a Carbonate Reservoir, Onshore Abu Dhabi, UAE
Authors: Fares Wael , Dutta Ashim , Reddy Rathnakar , Baslaib Moahmed , El Shahat Ayman , Cardozo Luis Gerardo , Abdel Meguid Mohamed , Nasrallah Mena , Mubeen Muhammad , Aki Ahmet
Published: March 2023

To develop a mature onshore carbonate field in Abu Dhabi and reduce the footprint and cost, an artificial island has been built in shallow water that can accommodate drilling rigs and extended-reach wells. This paper presents a case study of the longest onshore well drilled in Abu Dhabi. Planning to drill such a deep well starts long before execution, using offset well data and extended-reach drilling (ERD) engineering. There were formation and reservoir challenges due to the uncertainty in the earth model in the horizontal section of the well. Hence, it was very challenging to maintain contact with the thin reservoir intervals, without approaching the boundaries. In addition, the limited power available to drive the drillstring and maintain circulation drove the ERD engineering team to find optimum solutions, including drillstring and bottomhole assembly (BHA) design. Furthermore, there was a known risk of differential sticking, which meant that the use of radioactive sources in the BHA was undesirable. The well was planned to be drilled in two runs, using nuclear measurements in the first run and non-nuclear measurements in the second. A well-placement methodology and workflow was developed and integrated with the geological understanding of the target layer. Analysis of offset horizontal wells resulted in the delivery of an optimized BHA design, including careful selection of logging-while-drilling (LWD) technologies, to mitigate the geological challenges. The BHA also included a new generation of intelligent, fully rotating, high-dogleg, push-the-bit rotary-steerable system, to geosteer the well in the thin target layer while maintaining the planned target trajectory with minimum borehole tortuosity by means of real-time drilling optimization.

The extended-reach horizontal section was drilled successfully, and the geosteering objectives were achieved with 100% reservoir contact over a 20,000-ft interval, targeting a thin carbonate layer and overcoming the complex geological environment. The well was drilled to a record depth of 32,300 ft. The new intelligent rotary steerable system with automatic cruise control helped to eliminate any well-profile issues, minimize wellbore tortuosity, and maintain aggressive drilling parameters. The nuclear and non-nuclear LWD measurements, including NMR, helped to reinforce understanding of the reservoir properties along the entire section.

This success has opened the door for drilling more challenging wells. In addition, it has proved that proper planning and execution can shift the boundaries further and gave confidence to drill even deeper.