Definitive Dynamic MWD Surveys Generate Rig Time Savings and Flat Time Reductions in the Middle East

Wellbore surveying is a critical component of any well construction project. Understanding the position of a well in 3D space allows for the wells geological objectives to be carried out while safely avoiding other wellbores. Wellbore surveys are generally conducted using a magnetically referenced measurement while drilling tool (MWD) and taken while static, either before, after or sometimes during the connection. The drillstring is often worked to release trapped torque and time is often taken waiting for the survey to be pumped up. All of this consumes rig time and opens the wellbore up to wellbore instability issues. The application of definitive dynamic surveys (DDS) which are static MWD quality surveys taken while drilling and updated continuously. There is no longer a need to stop and take a static survey eliminating MWD surveying related rig time, reducing drilling risks from additional pumps off time and improving TVD accuracy and directional control. The rig time taken for surveying with and without DDS will be compared between similar wells in the field, and detailed analysis of relative tortuosity between DDS and non-DDS wells will also be conducted. Trajectory control analysis will be reviewed by looking at the difference in the number of downlinks between DDS and no DDS wells and also the deviation from the planned trajectory. An overall analysis of on bottom ROP will be made and an analysis as to the relative differences in TVD between static and DDS survey will be carried out. This abstract will outline the rig time and operational savings from DDS, it will detail the surveying time savings, directional control improvements, TVD placement differences to static surveys and provide costs savings as a comparison to previous similar wells. This will be outlined over a number of wells, divided by sections as the wells are batch drilled and provide an insight into the benefits of DDS on a drilling campaign. Some discussion will be made as to the efficacy of the DDS surveys and how their error model has been developed. DDS is a unique and novel way of taking surveys while drilling, providing static MWD quality without the added rig time costs but at a much higher frequency that the typical once a stand survey program. This paper outlines the cost and process savings associated with using the DDS surveys.

Reduction in Backup Tool Requirements: Risks vs. Benefits, a Probability Analysis

Summary A review of the use of measurement while drilling (MWD), logging while drilling (LWD), and directional drilling (DD) tools mobilized to offshore drilling units in the North Sea highlighted an opportunity to lower operational cost for the operator and reduce capital used for the oilfield services company. An objective was set to develop a risk-based probability model that would assess the positive and negative financial impacts of reducing, or perhaps entirely removing, backup tools in this historically risk-averse basin. The scope of the initial analysis was a drilling campaign on a single rig contracted by the operator (Rig A). This analysis was then extended to review scenarios in which several operations in close proximity would share backup tools. The last 3 years of MWD/LWD/DD tool reliability data from North Sea operations, recorded by the oilfield services company, were used as an input. To assess the probability of failure, a binomial model was developed to create a binomial distribution for each tool to calculate the probability of having zero to X failures for a selected tool or bottomhole assembly (BHA) for a given number of runs. Three binomial models were developed to study the effect of “easy,” “moderate,” and “challenging” drilling environments on tool reliability. A financial risk model was designed to balance the probability-weighted cost of failure for the operator against the lower costs resulting from reduced tool provision by the oilfield services company. To better estimate risks and financial impacts on the project, a sensitivity analysis was performed on the financial risk model using the three binomial models. As a result of the analysis, it was demonstrated that recent improvements in tool reliability support a reduction in the provision of backup MWD/LWD/DD drilling tools for the majority of North Sea drilling scenarios.

Utilizing High-Frequency In-Bit Sensor Data Improves Drillbit Design and Modelling

Modern drill bits designs have become more efficient using static modelling, and in more advanced cases, time-based dynamic modelling. These methods have created improved cutting structures that fail rock more effectively, however, at-bit vibrations are difficult to estimate because of the high-frequency nature of the vibration and its proximity to typical vibration sensors. In conventional applications, vibration is not measured near the bit. A solution to capture this data on conventional assemblies and use the data in an actual bit design is presented in this paper with subsequent performance and vibration results. The relative efficiency, bit dull grading, and vibration performance are compared across these designs and explored in depth. This new generation of vibration tool fits inside the bit pin, enabling accurate at-bit vibration measurements by a suite of sensors. The tool includes a tri-axis accelerometer that measures lateral and axial acceleration, and gyro sensors to measure rpm and torsional acceleration. Together, these outputs combine with the rig surface data to have time- and depth-based vibration data in the context of the run. When used to quantify the dynamic model, this represents a modelling calibration that improves bit design performance. The lower-vibration environment created by the new bit design enables the operator to run increased parameters with a lower likelihood for measurement-while-drilling (MWD) failures, motor failures, and premature catastrophic bit failures leading to faster run times and less nonproductive time (NPT). These results also prove that meaningful bit design changes can take place more frequently than through traditional means, translating value to the operator in the form more successful BHA improvements and less drilling time. Using the new in-bit sensor in a baseline design to start the design cycle, a baseline mechanical specific energy (MSE) and vibration model was developed foot-by-foot. The worst areas of vibration were seen as the bit became dull in the lower section of the drilling interval. A new dull bit model was created in parallel to capture this section of data. A new design was proposed to Whiting Petroleum to improve both sharp and dull efficiency and vibration, and subsequently run with sensor in an offset well.

Integrated Underreamer Technology with Real-Time Communication Helped Eliminate Rathole in Exploratory Operation Offshore Nigeria

This paper describes the successful deployment of integrated underreamer technology with real-time communication through mud-pulse telemetry system, to drill and eliminate rathole in 17 1/2-in × 20-in successfully in one run and helped set casing as close as possible to the depth of suspected pressure ramp on an exploratory well offshore Nigeria. This technology uses the same communication system (actuator bypass) as Measurement While Drilling tools (MWD), Logging While Drilling tools (LWD) and Rotary Steerable System (RSS). Integrated underreamers broadly used in the drilling operations support optimized casing and completion programs and helps reduce operational risks such as wellbore instability. The ball drop and hydraulically activated reamer technologies available today comes with limitations and HSE risks. The distinctive functionalities of the integrated underreamer technology described here, such as unlimited and fast activation and deactivation via downlinking and real time downhole feedback, reduce uncertainties and operational costs in the complex and challenging deep offshore drilling operations. The real-time communication through mud-pulse telemetry system enabled the placement of integrated underreamer 6 meters from the bit thereby reducing rathole length to approximately 9 meters compared to 80 meters for conventional underreamer application. The integrated underreamer is compatible with existing RSS and provide unlimited activation cycles. The integrated underreamer offers flexibility in placement in the bottom hole assembly (BHA) and it can be used as a near bit reamer, or as main reamer or as both. In this case, the integrated near bit underreamer eliminated the need for a dedicated rathole removal run. It also offered a feedback confirmation of the cutter blades activation status and provided hole opening log thereby reducing the operational uncertainties for the under reaming, saving rig time up to 16 hours for shoulder test. The underreamer was successfully deployed to drill and ream the challenging 14 ¾" × 17 ½" and ream 17 ½" × 20" section offshore Nigeria. Both sections were drilled and reamed to section Total Depth (TD) in one run with all directional reuirements and Measuring While Drilling (MWD)/Logging While Drilling (LWD) met saving client approximately 4 days of rig spread cost. The reamer appeared to provide an in-gauge borehole allowing for successful running and cementing of liners without any issues, demonstrating superior borehole quality. The new Technology proved to be a reliable and flexible hole enlargement while drilling solution that help to improve drilling performance, reduce operational risks and save cost.

Correcting Subsurface Seismic Depth Uncertainty in Real-Time Using Reservoir Navigation Distance-to-Bed Mapping

The most common challenge in horizontal drilling is depth uncertainty which can be due to poor seismic data or interpretation. It is arguable that a successful landing of the wellbore in the reservoir optimally and within the desired zone is the most challenging in most geosteering operation. The presence of fluid contacts such as oil-water-contact (OWC) and gas-oil-contact (GOC) complicates the whole drilling process, most especially if these fluid contacts are not well defined or known. Additionally, the ability to map the boundaries of the reservoir as the BHA drills the lateral section is an added advantage to remaining within the desired reservoir section. The success of any reservoir navigation service where seismic uncertainty at the reservoir top is high will rely largely on how effective the geosteering system is and how the geosteering engineer is able to react promptly to changes while landing the well in the reservoir and drilling the lateral section with without exiting the reservoir. Reservoir Navigation Service (RNS) provides the means for the drilling near horizontal or horizontal wells for the purpose of increasing hydrocarbon extraction from the earth's subsurface. This involves the use of a pre-defined bottom hole assembly (BHA) with inbuilt downhole logging while drilling (LWD) and measurement while drilling (MWD) sensors. The measurements from these downhole sensors are uplinked to the surface of the wellbore where they are converted to meaningful petrophysical data. The goal is to use the downhole petrophysical data such as gamma ray, propagation resistivity and so on, to update an existing pre-well geological model of a section of the earth in such a way that the final result depicts the true model picture of the earth subsurface. This paper focuses on using well CBH-44L to showcase how the use of real-time distance-to-boundary (D2B) measurement from a deep reading azimuthal propagation resistivity tool is use to correct for depth uncertainty in seismic, thereby, improving the chance of successfully landing and drilling a horizontal well.

Specifics of MWD Data Collection and Verification during Formation of Training Datasets

This paper presents a structured analysis in the area of measurement while drilling (MWD) data processing and verification methods, as well as describes the main nuances and certain specifics of “clean” data selection in order to build a “parent” training database for subsequent use in machine learning algorithms. The main purpose of the authors is to create a trainable machine learning algorithm, which, based on the available “clean” input data associated with specific conditions, could correlate, process and select parameters obtained from the drilling rig and use them for further estimation of various rock characteristics, prediction of optimal drilling and blasting parameters, and blasting results. The paper is a continuation of a series of publications devoted to the prospects of using MWD technology for the quality management of drilling and blasting operations at mining enterprises.