Intelligent Rotary Steerable System, Coupled with an Instrumented Bit, Delivers Section Plan in Deepwater GOM Project

The challenging offshore drilling environment has increased the need for cost-effective operations to deliver accurate well placement, high borehole quality, and shoe-to-shoe drilling performance. As well construction complexity continues to develop, the need for an improved systems approach to delivering integrated performance is critical. Complex bottom hole assemblies (BHA) used in deepwater operations will include additional sensors and capabilities than in the past. These BHAs consist of multiple cutting structures (bit/reamer), gamma, resistivity, density, porosity, sonic, formation pressure testing/sampling capabilities, as well as drilling dynamics systems and onboard diagnostic sensors. Rock cutting structure design primarily relied on data capture at the surface. An instrumented sensor package within the drill bit provides dynamic measurements allowing for better understanding of BHA performance, creating a more efficient system for all drilling conditions. The addition of intelligent systems that monitor and control these complex BHAs, makes it possible to implement autonomous steering of directional drilling assemblies in the offshore environment. In the Deepwater Gulf of Mexico (GOM), this case study documents the introduction of a new automated drilling service and Intelligent Rotary Steerable System (iRSS) with an instrumented bit. Utilizing these complex BHAs, the system can provide real-time (RT) steering decisions automatically given the downhole tool configuration, planned well path, and RT sensor information received. The 6-3/4-inch nominal diameter system, coupled with the instrumented bit, successfully completed the first 5,400-foot (1,650m) section while enlarging the 8-1/2-inch (216mm) borehole to 9-7/8 inches (250mm). The system delivered a high-quality wellbore with low tortuosity and minimal vibration, while keeping to the planned well path. The system achieved all performance objectives and captured dynamic drilling responses for use in an additional applications. This fast sampling iRSS maintains continuous and faster steering control at high rates of penetration (ROP) providing accurate well path directional control. The system-matched polycrystalline diamond (PDC) bit is engineered to deliver greater side cutting efficiency with enhanced cutting structure improving the iRSS performance. Included within the bit is an instrumentation package that tracks drilling dynamics at the bit. The bit dynamics data is then used to improve bit designs and optimize drilling parameters.

Determining Hole Size and Washout by Running a Fluid Caliper, for Cementing Purposes

This paper describes the procedure to perform a fluid caliper and how by using fluid dynamics concepts, average hole size can accurately be determined, helping to derive the amount of hole washout and the appropriate amount of cement needed to circulate or achieve desired cement height. This process has been successfully performed on over 40,000 Permian Basin wells in West Texas and Eastern New Mexico, as well as numerous other basins in the United States. This includes vertical, directional, and horizontal wells of varying hole sizes and depths, from surface to production hole. This paper will provide real world examples, discussion of geological formations encountered, drilling fluids used, and the ultimate benefit a fluid caliper provided each operator through the accurate estimation of cement volume for the reduction of waste and satisfaction of well design and regulatory requirements. This paper will demonstrate that fluid calipers add to the operational efficiency of most drilling operations and should be considered a "Best Practice" for most drilling programs as their use can greatly limit the need to remediate a cement job necessitating additional downhole tool runs, wasting additional valuable rig time. Also, to be addressed are the limitations of fluid calipers including lost circulation, turbulent flow, and human error. Cementing is an integral part of the process to ensure wellbore longevity, requiring increased attention. Field practice of pumping nut plug, dye, or other markers to estimate required volumes is outdated and inaccurate. This paper will clearly identify the reasons why the modern fluid caliper is aligned with today's heightened focus on ESG. Environmentally, fluid calipers determine the proper amount of cement to prevent waste. Regarding safety, fluid calipers help ensure the operator pumps accurate cement volumes to cover corrosive and/or productive zones to prevent unwanted annular influx, and referring to governance, fluid calipers help the operator pump adequate cement volumes to satisfy well construction regulations.

Measuring and Analyzing the Magnetic Content of Drilling Fluid

Magnetic contamination of drilling fluid can impact the accuracy of a directional survey by shielding the magnetic field. Additionally, this contamination, such as swarf or finer magnetic particles, can agglomerate on the downhole tool or BOP and cause tool failure in the worst-case scenario. Thus, it is necessary to measure the magnetic content of drilling fluid. However, there is no recommended practice in API or ISO for this purpose. A simple experimental setup and measurement system was developed that can be easily deployed in the rig site to measure the magnetic contamination of drilling fluid. 47 drilling fluid samples were collected from a multilateral production well drilled with a semi-submersible drilling rig located in one of the North Sea's fields. The magnetic content of these samples was measured using the established method, and the microstructure of the collected content was analyzed using a scanning electron microscope (SEM) and x-ray diffraction analysis (XRD). Ditch magnets are commonly installed in the flowline on the rig to remove the swarf and finer magnetic particles, if the design is optimized. Ditch magnet measurement data of the well that the drilling fluid samples were collected from is presented. Operational details and common factors that might increase the production of the magnetic content were also investigated. By comparing the measured magnetic contamination of the drilling fluid samples and ditch magnet measurement data, it was possible to evaluate the efficiency of the ditch magnet system.

Optimized Multi-Zone Dynamic Reservoir Evaluation in the Middle Caspian

Caspian offshore is reach for hydrocarbon reserves. The fields are made of multi-zone carbonate and sandstone reservoirs with significant variation of properties having high pressure (HP), high temperature (HT) and high H2S concentration in reservoir fluid. These challenges pose significant challenges to conduct the formation and multi-zone reservoir testing in a safe and informative manner. The dynamic reservoir evaluation program consists of formation pressure and its profile measurements, fluid pump-out for confirming the fluid type and sampling performed with wireline formation testers (FT) in open-hole and multi-zone well test for productivity estimation with drill-stem test (DST) designed for offshore environment with HP and high H2S. The project was planned and executed in an integrated manner, where the well construction design and selection of drilling and completion fluids has to improve the chance of success for FT and DST by taking into accound the downhole tool sizes and complex geological conditions. The open-hole formation testing and well testing in cased-hole were combined to provide enough information for characterizing multi-zone reservoirs by minimizing the drilling rig time. The well testing program was optimized in terms of number of zones for testing and necessity to acidize the reservoir based on formation testing data. The given methodolgy allowed to efficiently conduct the formation testing and well testing at two recently drilled offshore wells with multi-zone reservoirs. It was the first integrated dynamic reservoir evaluation project for such complex geological conditions in Middle part of Caspian offshore. This paper demonstrates the lessons learnt from two wells and offers the methodology for planning the evaluation for similar fields.

Successful Intervention of Coiled Tubing Rugged Tool with Real-Time Telemetry System in Saudi Arabia First Multistage Fracturing Completion with Sand Control System

An openhole multistage completion required selective fracture stimulation, flow control, and sand control in each zone. An openhole multistage completion was designed by combining a production sleeve integrated with sand screens and inflow control devices and a fracture sleeve with high open flow port. The system was designed to use a ball drop to isolate the bottom intervals while fracturing upper intervals. After fracture stimulation, the fracture seat/ball needed to be milled. The production sleeve were designed to be shifted to the open position and the fracturing sleeve to the closed position through mechanical shifting tool to put the well on production. The fracturing sleeve and the production sleeve were located close to each other and a successful shifting operation needed an appropriate shifting tool, with a real-time downhole telemetry system that met the temperature limitations while providing accurate depth control, differential pressure readings, and axial force (tension and compression) measurements. Hydraulic-pressure-activated shifting tools were used to manipulate the sleeves. A coiled tubing (CT) rugged downhole tool with real-time telemetry was used to run the shifting tools. Yard tests were conducted to identify the optimum rates and pressures to actuate the hydraulically activated shifting tools and study their behavior. The expansion of the fracturing sleeve shifting tool keys initiated at 1.6 bbl/min (400 psi) and the keys were fully expanded at 1.8 bbl/min (600 psi), whereas the expansion of production sleeve shifting tool keys initiated at 0.3 bbl/min (700 psi), and the keys were fully expanded at 0.4 bbl/min (900 psi). During the design and planning of the shifting operation, simulations were conducted, and surface and downhole tools were selected carefully to ensure the CT could provide enough downhole upward force (5,000 to 6,000 lbf) to close the fracture ports and 2,000 to 4,000 lbf to open production sleeves. Following the fracturing operation, the first CT run aimed to mill fracture seats/balls to clear the path for the subsequent shifting operation. In the second CT run, all the fracturing sleeves were shifted to the closed position while production sleeves were shifted to the open position. The CT rugged downhole tool proved critical for depth correlation and accurate placement of the shifting tools. The real-time downhole acquisition of differential pressure across the toolstring also allowed operating the shifting tools under optimum conditions, while downhole force readings of tension and compression confirmed the shifting of completion accessories. Two fracturing sleeves were shifted to the closed position at 2.4 bbl/min and 700-psi downhole differential pressure, with the downhole weights of 700 lb and 1,000 lbf. Three production sleeves were shifted to open position at 0.6 bbl/min and 1,200-psi downhole differential pressure, and the maximum surface and downhole weights recorded were 73,000 lb and 19,200 lb, respectively. That operation led to sand-free production and confirmed the success of the first multistage completion enabling fracturing operation and controlling sand production in Saudi Arabia. This study describes the use of real-time downhole measurements and their significance when surface parameters do not give clear indication of shifting. It also features the first-time use of two hydraulically activated shifting tools operated during the shifting operation in Saudi Arabia's first multistage completion enabling fracturing operation and controlling flow/sand production.

The Shaped PDC Cutter and Special Bit Element Utilization to Improve Overall Drilling Performance in Hard Massive Carbonate: A Case Study of ERD Horizontal Well In Offshore East Java, Indonesia

Drilling through hard massive carbonate formation combined with naturally induced torsional vibration due to bit-formation interaction is often resulting in unnecessary down time caused by downhole tool failures, sub-optimal drilling performance and extra trip to change out worn out bit. The torsional vibration is also well known as as stick and slip. To address the challenge, special PDC bit with advanced cutter technology were utilized in ERD well in Offshore East Java. The key focus when selecting the bit was on PDC cutter shape selection to improve drilling efficiency and utilization of higher strength material elements to improve stability and impact durability of the cutting structure critical in drilling hard and harsh rocks. The bit record, bit type configuration, QA/QC process, hydraulic & stability analysis and secondary cutter materials consideration were also specifically analysed when selecting this bit to improve bit performance further and ensure the bit could be repairable & reusable after being used. The first field run of the bit incorporating all this technology mentioned above was performed on last two (2) ERD well drilled in East Java Offshore area, at the 8.5in hole section with 7 bladed, 16mm cutter. The bit successfully drilled total of 3,029 ft interval through massive carbonate formation for both wells. The bit reached target depth without bit change. The bit had proven to reduce drilling torsional vibration stick & slip from severe to medium level. Both bit run also had set considerably remarkable slip-to-slip Rate of Penetration (ROP) for ERD wells category, which had significantly improved by 69.35% compared to previous ERD well drilled in same carbonate formation with ERD profile. When on surface, the bit was observed still in excellent condition for this application. The enhanced PDC bit selection had proven to enable drilling into more challenging torsional vibration induced formation in massive Carbonate formation and challenging ERD trajectory thus improving overall drilling performance and achieve actual rig time & cost saving compared to plan.

A Challenging Drilling Campaign Unleashed a Unique Fast Drill String Recovery Methodology Eliminating Utilizing Wireline, CT and Overcome Highly Deviated String Accessibility

Stuck pipe is one of the biggest challenges in the drilling sector and is a multi-billion-dollar issue. Recovering from stuck pipe absorbs significant cost and time. Durations for stuck pipe events and recovery can be mostly variable from a few days to up to over a month to resolve. When attempts to release the stuck pipe by jarring or acid fail, the operating company and drilling contractors are left with little option but to sever the drill string and prepare for side-track operations or even abandon the hole. Traditional pipe severance methods in the event of a stuck pipe situation typically take significant time (often days, and sometimes weeks), require specialist tools, Service Hands, and are usually reliant on wireline services to deliver the severance method. In 2018, a Major Operating Company in UAE faced a challenging high-sticking Formation, which caused massive NPT, stuck of drill strings, and loss of drilled section holes. Brainstorming within the Drilling Engineering team took the campaign to the next level of pre-planning to reach deep access in the hole to be able to achieve zonal isolation by spotting cement plugs through drilling BHA, find a solution to save the hole and recover the pipes in an efficient, cheap and productive manner. An environmentally safe pre-planned solution to severe the drill string was proposed to help save the wells and allow an excellent methodology to save the wells/fields from stuck pipe risks. The engineering solution allows a fast recovery of drill pipes using a downhole tool as a part of drilling BHA, with the option to activate it if required, by dropping a smart dart and circulating with mud for a specific time to apply cut string with two option, either spotting cement with recovered BHA or lift BHA with fish neck to try to fish in the hole.

IMPROVING RESERVOIR TESTING AND SAMPLING IN H2S CONTAMINATED FLUIDS BY ADAPTING STATE-OF-THE-ART SEMICONDUCTOR THIN FILM TECHNOLOGY FOR DOWNHOLE TESTER TOOLS

Accurate reservoir fluid identification and sampling of hydrogen sulfide (H2S) contaminated fluids is difficult to achieve due its consumption by the interior of downhole tool surfaces prior to sampling or measurement. For low PPM level concentrations, this fact does not change, despite recent tool advances utilizing NACE compliant materials. Consequently, H2S concentrations are typically under-reported which adversely affects production and presents significant health safety and environment concerns. Historically, only sampling bottles have been coated to preserve H2S concentrations during transit to laboratories with a material that is resistant to H2S reactivity to enable more representative measurements. However, only very recent efforts have transitioned the focus toward successfully coating the interior of the tools. This paper details a state-of-the-art technology, initially developed and heavily leveraged from the semiconductor industry. The technology is adapted to coat the interior surfaces of downhole tools with a chemically resistant dielectric thin film. New developments now provide the benefit of the process being safe, able to be performed at atmospheric pressure and temperature conditions, and portable; thus, allowing the coating process to be deployed to field locations. The method involves atomic layer deposition (ALD) technology to be plumbed in directly to a downhole tool and conformally deposit a thin layer (e.g. < 1 micron) of highly durable H2S-resistant sapphire to the entire interior tool surface. An automated procedure has been developed allowing the versatility to accommodate a number of unique geometries inherent of different formation tester configurations. New advances in Quartz Crystal Microbalance sensors are also realized in-situ to optimize (in real-time) the efficiency of the process and ensure uniform and conformal coverage is obtained in the fastest and safest manner. Laboratory testing on a prototype system demonstrated uniform and conformal coverage of a ~ 500 nm thick sapphire film resistant to flaking and scratching. Accelerated lifetime stress testing demonstrated high durability relative to expected tool life. Testing of coated and uncoated tools show the coating is successful at the 50ppm level H2S for up to 4 days. These results are contrasted with similar tool body samples not coated with the H2S-resistant ALD sapphire and subject to the same H2S conditions. To show the coating’s durability, subsequent experiments flowed mud-based drilling fluid through both the tool body and sample chambers, followed by thorough cleaning and successful repeating the same 50ppm H2S test. Exposure of the sapphire coated tool body and sample chambers to various concentrations of H2S demonstrated zero loss. Ultimately this technique represents a new opportunity to gather representative formation samples containing low concentrations of H2S.

A Business Case for Drilling Automation: Well Cost Compression by Suppressing Downhole Tool Failure in Low Oil Market

In a difficult situation where the oil market is down, reducing drilling cost is always an interesting outlook to be pursued. To do so, one should consider looking at the highest component on the drilling cost. Down-hole equipment failure and stuck pipe is avoidable during the engineering planning. It is well-known that billions of dollars have been lost and numerous Bottom-Hole Assembly (BHA) are left in the well due to such problems, related to stick-slip phenomenon. Thus, despite the low oil price, it is a new normal that some asset owners opt to invest on high-end tools to prevent stick-slip, meanwhile others are still reluctant because of its high initial costs and chose to solely focus on the technical skills to drill faster. The objective of this paper is to determine whether, and which, utilization of these automations will be an effective method to lower overall cost, between using Anti-Stick Slip Technology (AST), Surface soft-torque, Self-Adjusting PDC Bit or all three combined together. The analysis of this project is conducted by providing conjecture in comparative method to visualize the configuration. In each case, estimated Rate of Penetration (ROP) is observed based on the recent literature of its application in similar lithology which is carbonate and interbedded shale. As the ROP increases, the overall drilling cost along with percentage of potential net saving for each case is evaluated in this study and select the most effective strategy. The outturn suggests that despite the high initial investment, combining all technologies are economically advantaged. With the DOCC by the self-adjusting PDC bit and torque alleviation by AST to handle the rock interface in addition to BHA torque wave mitigation from surface by surface soft torque, the ROP is quantified as summation of all cases’ ROP gained as the tool complements each other. The estimated ROP of the case significantly gives high decrement of the overall cost and boosted the potential net saving. Moreover, prevention from NPT due to downhole failure and stuck pipe problem is also a contributing factor to increasing cost efficiency. Therefore, combining all the tool together is proven to be the most favorable option aside from, respectively from preferable to the less, utilizing Surface Soft Torque, Self-Adjusting PDC Bit, and AST. Although it requires high initial investment, it is worthwhile to explore the usage of automation technologies for the overall cost reduction contributes to make the case financially attractive.

Hybrid Electro-Optical Cable Continuously Powers Downhole Coiled Tubing Telemetry and Enables Time and Carbon Footprint Reductions During Extensive Cleanout Interventions

On the Norwegian continental shelf (NCS), coiled tubing (CT) cleanout requires small bites and frequent wiper trips to the surface due to potential sand bedding in a large and deviated completion. A real-time CT downhole measurement system is used to optimize the operation, following a dynamic workflow. Conventionally, the system is powered by downhole lithium battery, which limits CT downhole operating time. A continuous surface-powered system was needed to promote further optimization for such operation. A new hybrid electro-optical cable was introduced to enable continuous power supply from surface to the real-time downhole tool sensors. The system consists of a surface power module that sends power through a layer of low-DC-resistance conductors and optical fibers that enable data telemetry. Conventionally, only three to four trips can be completed before replacement of the downhole battery is required. Battery replacement can take up to 8 hours due to the complexity of that offshore environment. With the continuous power supply, the CT cleanout operation can continue for days without interruption of data from the downhole tool sensors. A three-well CT cleanout campaign in the NCS demonstrated the benefits of this new real-time downhole measurement system by using accurate downhole weight and torque readings to control the penetration through scale and avoid motor stalls. Sections of scale bridges were identified during the cleanout by monitoring fluctuations of downhole torque of the mill. The monitoring allows CT operators to control penetration rate and bite length during the cleanout. When the milled debris are swept, downhole weight is used to detect early signs of solids plugging around the mill. Downhole pressures complement surveillance of the sweeping of solids to the surface by giving a qualitative measurement of solids loading through conversion of the real-time bottomhole pressure reading into equivalent circulating density with changing CT depth. The process of optimizing bite length and sweeping speed is repeated without interruption thanks to continuous power supply from the surface, eventually leading to time reduction. In one of the wells, downhole tools uninterruptedly acquired data for 10 days straight. The CT managed to clean out a total of 40 908 kg of a mixture of scale and sand, with an estimated average time reduction of 25% when compared to CT cleanout without real-time downhole data. Delivery of continuous high-voltage power to downhole tools not only enables reduction in operating time, it also paves the way for extending the capabilities of CT interventions by enabling the operation of more electrically activated application tools. It allows combining multiple work scopes in a single CT run, which reduces operating cost and provides greater operational flexibility. Finally, eliminating the dependency on lithium batteries reduces the carbon footprint for a more sustainable operation.