Pre-job Planning Research Articles

Past, Present, and Future Applications of Ultradeep Directional Resistivity Measurements: A Case History From the Norwegian Continental Shelf

With the introduction of ultradeep azimuthal resistivity (UDAR) logging-while-drilling (LWD) tools toward the beginning of the last decade, the oil and gas industry went from real-time mapping of formation boundaries a few meters from the wellbore to tens of meters away. This innovation allowed early identification of resistivity boundaries and promoted proactive geosteering, allowing for optimization of the wellbore position. Additionally, boundaries and secondary targets that may never be intersected are mapped, allowing for improved well planning for sidetracks, multilaterals, and future wells. Modern tool design and inversion algorithms allow mapping the reservoir in 3D and exploring the sensitivity of these tools to the electromagnetic field ahead of the measure point for look-ahead resistivity. Improvements in the technology over the past decade have changed the way wellbores are planned, drilled, and completed, and reservoir models are updated. This paper presents a case study summarizing the advances in UDAR measurements and inversions over the last decade. The case study presents the whole workflow from prejob planning, service design, and execution of one-dimensional (1D) and three-dimensional (3D) inversion in addition to the future potential of look ahead in horizontal wells. Prewell simulations provide a guide to expected real-time tool responses in highly heterogeneous formations. This identifies how far from the wellbore 1D inversions can map major boundaries above and below the well. A fault was expected toward the toe of the well, and UDAR was used as a safeguard to avoid exiting the reservoir. Standard 1D inversion approaches are too simplistic in this complex geologic setting. Thus, 3D inversion around the wellbore and ahead of the transmitter is also explored to demonstrate the improvements this understanding can bring regarding geostopping toward the fault and reservoir understanding in general. Successful geosteering requires personnel trained to handle complex scenarios. Geosteering training simulators (GTS) could be efficient tools for training to interpret inversions where the “truth” is known from realistic 3D model scenarios. The team can learn how to best exploit UDAR technology and inversion results within its limits and not extend the interpretation beyond acceptable uncertainty levels. It will also be addressed how the understanding of inversion uncertainty could be updated in real time in the future. The continued future success of UDAR technology and 1D to 3D inversion results for look-ahead and look-around applications will depend heavily on uncertainty management of the inversions to avoid wrong decisions and potentially reduced well economy.

Improved Drilling Efficiencies Using Offline Cementing Saves Time, Reduces Costs

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 196600, “Improved Drilling Efficiencies Using Offline Cementing Saves Days on Well and Reduces Costs,” by Samuel Van Meter, SPE, and Kristin Kutchak, SPE, Halliburton, and Habib Guerrero, SPE, Inflection Energy, prepared for the 2019 SPE Eastern Regional Meeting, Charleston, West Virginia, 15–17 October. The paper has not been peer reviewed. Drilling in the Appalachian Basin in Pennsylvania has evolved since its inception. Operators have shifted their focus from mere wellbore delivery to delivering wells in the shortest amount of time to reduce risks and costs and drive efficiency. The complete paper presents a case study in which offline cementing improved operational efficiency by reducing drilling times and provided significant cost savings. Introduction For decades, the focus during drilling operations has been on achieving faster rate of penetration (ROP) and drilling time to reduce well costs. However, the significance of ROP improvement accounts for less than 25% of the full well-construction cycle. Many areas with possible efficiency gains have yet to be explored within the cycle. When an operator began making plans to switch from traditional drilling (top-down drilling of surface through production sections, per well) to batch-set drilling (drilling all surface sections, followed by all intermediate sections, then all production sections), the service company proposed the offline cementing method as a cost-saving and efficiency-conscious measure. Theory and Definitions The concept of offline cementing itself is quite simple: The openhole section is drilled, and casing is run to total measured depth and hung in the wellhead. Then, the rig skids to the next well, begins rigging up, and drills the next openhole section. While the rig is preparing on the next well, the cement-service provider can perform operations on the previously drilled or cased well section. Risks with this type of operation were assessed during pre-job planning. Multiple risk assessments were conducted on location before the onset of operations, and a job-site analysis (JSA) was also completed. Pennsylvania state regulations dictate that, on surface and intermediate strings, cement must reach a compressive strength of 350 psi and a minimum static time of 8 hours before moving forward with operations after the primary operation. Because of this wait time, off-line cementing is ideal. Operators can skid the rig, leaving the cemented pipe to cure while rigging up on the next well. This helps increase efficiency by minimizing the nonproductive time (NPT) incurred during the 8-hour wait time.

Investigating the Benefits of Rotating-Liner Cementing and Impact Factors

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 180578, “Investigating the Benefits of Rotating-Liner Cementing and Impact Factors,” by Quek Khang Song, SPE, Hao Wang, and Weicun Dong, Halliburton, and Roger Bradshaw, SPE, Wei Cui, and Johnson Njoku, ConocoPhillips, prepared for the 2016 IADC/SPE Asia Pacific Drilling Technology Conference and Exhibition, Singapore, 22–24 August. The paper has not been peer reviewed. Effective primary cementing in the wellbore is critical to achieving positive wellbore isolation. This paper discusses an expandable-liner-hanger (ELH) system that provides liner rotation during the liner deployment and the cementing operation while providing a hydraulically energized liner-top seal upon setting. The case histories of the wells using the system verify the key consideration factors presented in this paper, which help improve the quality of the liner cementing bond. Liner-Hanger System The ELH system incorporates bonded elastomeric sections. The elastomeric element provides the hanging capacity for the liner and a gas-tight seal. The liner-hanger/packer body contains no setting mechanism or external components, such as slips, hydraulic cylinders, or pistons. The hydraulic setting mechanism is contained in the setting-tool assembly and is retrieved, eliminating potential leak paths in the flow stream. This running/setting-tool-assembly system provides the necessary expansion mechanics, cementing pack-off seals, a collet assembly to carry the liner weight and transfer the liner weight to the drillstring, and an end-of-expansion indicator assembly. As required, the liner system can be rotated and reciprocated when incorporated with an ELH high-torque running/setting tool and high-torque liner connections. The liner system can be rotated and reciprocated while running in the hole or during cementing operations (Fig. 1). Liner-Hanger Operation The key to a successful liner deployment is prejob planning. As part of the preplanning, several iterations of the torque-and-drag analysis are simulated with software to determine the ideal run-in-hole solution. The ELH system is run much like conventional liner-hanger systems, with minimal differences. The key difference is that the liner with the ELH system is cemented before setting the hanger because the hanger provides hydraulic isolation when it is set. Cementing before setting the liner hanger enables rotation and reciprocation, which should improve the cementing. No liner reciprocation during the cementing operation was planned because of rig limitations. In addition, rotation was preferred over reciprocation because the liner must be in the position across the zones of interest at all times and prevent any potential operational risk (e.g., stuck pipe or liner set high). The ELH standard setting/running tool has a torque rating limitation of 15,000 lbf-ft. Consequently, it was deployed as a non-rotational liner hanger. The ELH high-torque running/setting tool, with a torque rating of 39,071 lbf-ft, was used with the rotational liner-hanger system. During the cementing operation, the liner string was rotated at 10 to 20 rev/min. The next step is to set the hanger, which is performed hydraulically after releasing a set-ting ball. After the hanger is set, the liner top can be washed using conventional or reverse-circulation techniques. The tools are then retrieved from the wellbore, and the well is ready for completion.

Fluid-Hammer Effects on Coiled-Tubing Friction in Extended-Reach Wells

Summary The lateral reach and residual bottomhole-assembly (BHA) loads in extended-reach wells strongly depend on the coiled-tubing (CT) mechanical friction. Detailed CT-friction modeling becomes crucial in the prejob planning stage to ensure successful job predictability. However, current numerical simulators consider constant coefficients of friction (CoFs) that are determined from similar operations without taking into account the effects of the operational and downhole parameters on the CoF for a specific operation. This study outlines the modeling of CT-friction force, CoF, and axial BHA loads depending on the operational and downhole parameters when a fluid-hammer tool is used. Recent theoretical, laboratory, and field data have established how CoF depends on the downhole parameters (Livescu and Wang 2014; Livescu and Watkins 2014; Livescu et al. 2014a, b; Livescu and Craig 2015). Previously, these effects were not considered in the CT numerical models, leading to significant CoF differences among available commercial simulators. For instance, the default CoFs in the current prejob simulations for cased holes, when no lubricant or friction-reducing tools such as fluid-hammer tools and tractors are used, vary between 0.24 and 0.30 or even higher. This makes it extremely difficult to consistently evaluate and compare the friction-reduction effects of lubricants, fluid-hammer tools, and tractors in extended-reach wells, especially when the field operator may be consulting with several service companies that use different commercial force-modeling software. This study presents the CT-force matching and fundamental physics on the basis of modeled fluid forces, including radial forces, drag forces, and, most importantly, pressure forces on the CT-friction forces caused by fluid-hammer tools. Extending the method of characteristics, regularly used for studying pressure pulses in straight pipes, the perturbations method also accounts for the helical shape of the CT. The new CT fluid-hammer model is validated against laboratory data. This rigorous method for calculating the axial BHA load and reduced CT-friction force caused by radial vibrations can be easily implemented in currently available tubing-force analysis (TFA) software for CT operations. This novel approach, which uses detailed CT mechanical-friction modeling to take into account parameters such as temperature, internal pressure, pumping rate, and others, improves predictions for CT reach in lateral wells. These findings broaden the current industry understanding of the CT mechanical friction modeling in extended-reach wells, and show benefits for the industry when considering variable friction modeling in commercial CT simulators.

Identifying construction supervisor competencies for effective site safety

Construction supervisors are crucial to eventual site safety performance. In the United States, the OSHA 30-hour training is becoming the de facto standard for supervisor safety competence. A literature review of recommended supervisor safety competencies reveals gaps when compared to the OSHA 30-hour training contents. We address this gap by identifying the necessary knowledge-based safety competencies that are most important for the front-line construction supervisor and prioritizing them for the first time. A Delphi process confirmed that knowledge of pre job planning, organizing work flow, establishing effective communication, and of routine and non-routine work tasks are highly important competencies for the construction supervisor to possess. Construction organizations who utilize the 30-hour training for supervisor safety competence must recognize its limitations and ensure supervisors are equipped with these additional competencies to effectively manage site safety. Government agencies should also recognize the policy limitations of requiring the 30-hour training for supervisors.

Advanced Borehole Seismic Acquisition challenges and Successes in Large LNG Project

In this paper we will describe the operational success of largest offshore borehole seismic job which paved the way for several advance borehole seismic projects in Gorgon, Wheat-stone and other projects. The primary objective of the survey was to obtain true vertical time-depth relation and high resolution 2D image below and around the well path for better understanding of reservoir while secondary objective was anisotropy parameters estimation to improve the reprocessing of surface seismic. The followings were the main challenges to this project: Finding a suitable boat/crane for deployment of sources at safe distance from boat hull. Acquisition sequence was switching between different surveys i.e Walkabove and Walka-ways, which made acquisition quite complex. Finding a properly trained navigator for the job. Minimizing rig time Noise attenuation The followings are main conclusions and recommendations VSP modelling was essential for survey design Survey lines were optimized to minimize the rig time Good prejob planning is a key of operation success Poor coupling noise have successfully attenuated during processing Successful acquisition of a comprehensive Walkabove & Walkaways data sets. Combined Walkabove and Walkaway VSPs and Surface Seismic helped to better under-stand the reservoirs. Integration of different data sets multiply the value of each of the elements. Reliable time, depth and velocity information was achieved from Walkabove data set. Recommendations for future acquisition work based on lesson learned on first well.

Concurrent in-situ measurement of flow capacity, gas content and saturation

A new core-less testing capability has been developed to provide concurrent measurements of coal seam flow capacity and gas content at in-situ conditions. The fluid-based measurement principles are intended to overcome time constraints, accuracy limitations, and cost implications of discrete measurements attributed to traditional ex-situ measurements on core samples. Details of measurement principles, associated enabling technologies, and generic test procedures have been disclosed in a previous publication. In 2012 a number of field trials were conducted with this new service for both coal mine operators and CSG operators. This peer-reviewed paper will detail pre-job planning, well site execution, and data analysis for one of these trials, which involved testing several seams across two wells, and will illustrate comparison with data acquired using conventional testing techniques from offset wells. This peer-reviewed paper will also highlight key learnings and overall performance, and explain how the learned lessons can be applied to improve testing efficacy and data quality.

Downhole Visualization Software Brings Sandface Completions Into Real-Time Age

This article, written by Editorial Manager Adam Wilson, contains highlights of paper OTC 23626, ’Sandface Completions Enter the Real-Time Age With One-ofa- Kind Downhole Visualization Tool,’ by Tommy Grigsby, SPE, Ricki Jannise, SPE, Raymond Rubio, and Darrin Towers, Halliburton, prepared for the 2012 Offshore Technology Conference, Houston, 20 April-3 May. The paper has not been peer reviewed. The operation of downhole sandface tools has relied upon depth measurements, downhole indicators that use applied tension or compression noted on a surface weight indicator, and hydraulic pressure to verify service-tool positions in relation to the sandface assembly. The introduction of multiple-zone one-trip sandface completion systems led to the development of a visualization tool that provides the tool operator with additional information to validate conventional tool-locating methods. The Real-Time Visualization Service (RTVS) package provides detailed visualization of the sandface assembly, including the service string, providing another tool-location validation method and a prejob planning tool. The visualization software provides the capability to monitor operations at the rigsite or remotely from a real-time-monitoring site or home personal computer. Development Drivers A number of factors have converged to drive the development of real-time downhole visualization capability. First, well depths and well deviations are increasing. The Lower Tertiary play in the Gulf of Mexico has potential well depths to 33,000 ft, while other areas in the deepwater golden triangle use horizontal sandface completions with increasing horizontal lengths. Second, sandface completions have become increasingly complex as interval lengths have increased and interval segmentation is required to stimulate the reservoir effectively. Third, the higher rig rates for deep water have highlighted the need to reduce work-string trips and time by using tools that are multifunctional, adding further complexity. The RTVS system will use data from hookload, block movement, annulus pressure, and tubing pressure, along with a sophisticated algorithm that compensates for temperature and pipe ballooning. The program includes a visualization package that depicts the entire bottomhole sandface assembly, which is composed of the packer and screen assembly with the service tool string installed inside. Once at depth, the packer is set, anchoring the sandface assembly. The service string is then released, and the tool positions are determined for squeeze, circulating, and reverse positions for each interval to be treated. Completion-Planning Process The completion planning for the RTVS service is a stepped process, similar to what is being done today with the exception of more detail in each planning step. The planning process has three phases: prejob planning, real-time monitoring, and post-job analysis. Prejob Planning. Once the well completion is defined, a step-by-step completion procedure is created. A detailed completion schematic will normally accompany the completion procedure and is provided by the service provider. The completion schematic will list the specific completion equipment for the procedure and provides the proposed component depth, length, outside diameter, and inside diameter.

Advanced Production Logging of Horizontal Wells in North Oman

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper IPTC 13309, ’Advanced Production Logging Review of a Number of Horizontal Wells in the North of Oman,’ by T.K. Chang, SPE, Schlumberger, and L. Mieles and P.J. Tarabbia, SPE, Petroleum Development Oman, originally prepared for the 2009 International Petroleum Technology Conference, Doha, Qatar, 7-9 December. The full-length paper reviews the advanced-production-logging jobs performed during 2006–07 in several fields in north Oman. The paper includes the following: Prejob planning, recommended logging procedures, operational planning and considerations for different types of wells, and well-completion strategy Factors influencing horizontal production-logging jobs Evaluation, log quality control, and interpretation of results Success-rate optimization through candidate selection and best practices Introduction Petroleum Development Oman began drilling horizontal wells in the north of Oman in the 1980s. Since then, most development projects have used a high proportion of horizontal and multilateral wells to access reserves. Historically, downhole inflow patterns encountered in these horizontal wells have been challenging to measure and interpret. Recently, a viable production-logging tool (PLT) was identified to increase understanding of real-time three-phase flow to assist in production optimization and proper well and reservoir management. The full-length paper reviews and analyzes a number of logging jobs conducted in the fields of north Oman. With any well-related operation, it is important to discuss the success rate of obtaining data. Fig. 1 shows the success rate of the PLT in the producing oil fields of north Oman. Successful jobs are indicated by green and unsuccessful jobs by red. “Technical success” (amber) is on the basis of whether the logging objectives set before the job were met. In some cases, well-workover entries were performed on the basis of the findings from the PLT job, and some production gains have been recorded. The high success rate (13 successful logging jobs out of 18) was partially a result of proper candidate selection, but mostly a result of proper planning. Of the five unsuccessful jobs, two were a result of tool failures and three were either failure to log the entire interval of interest or inability to log because of operational constraints, giving poor-quality data.

Propellant-Assisted Perforating—An Alternative Stimulation Solution in Heavily Karstified Carbonate Reservoirs

Summary Two gas fields offshore Sarawak, Malaysia, are characterized by heavily karstified carbonate reservoirs. These reservoirs are typified by significant porosity and permeability heterogeneities such that large fluid-loss zones are commonly encountered while drilling the reservoir section. The drilling strategy for the subsea development wells called for the use of a solid drill-in liner as a contingency should major losses be encountered while drilling the reservoir section. This strategy stands opposed to using a predrilled liner. The use of a drill-in liner, however, necessitates perforating. Typically, completions in such reservoirs are acid stimulated to maximize productivity. Complete stimulation of the reservoir section is very difficult to achieve using acid-diversion techniques in a karstic environment because of the large variability in the permeability. Propellant-assisted perforating was considered because it achieves effective stimulation diversion, equally across the entire perforated interval. Modeling work indicated that fracture lengths of 5 ft or longer would propagate from each perforation tunnel. Such large propagation lengths greatly increased the probability of connecting the completion directly to karstic features in the reservoir, to provide enhanced inflow performance. Another significant benefit was that perforation and stimulation would take place in a single operation, thereby reducing the health, safety, and environment (HSE) risk associated with handling acid, while saving rig time. Two successful field trials, totaling three wells, will be presented in detail to illustrate this application for propellant-assisted perforating. The data presented include prejob planning, execution, and post-job inflow-performance analysis. The result was three world-class, low-drawdown wells, each capable of delivering 200 MMscf/ D, providing well capacity that met or exceeded expectations. Applying the propellant-assisted perforating technique in three subsea wells in heavily karstified carbonate reservoirs has proved that this technique can offer a highly effective stimulation method across the entire perforated interval in such an environment. Additionally, its usage eliminates the need for conventional, separate acid stimulation, saving rig time and costs while reducing HSE risks.

Implementation of a Shock and Vibration Mitigation Process: Achieving Real-Time Solutions and Savings

Summary Worldwide, the costs associated with the exploration and production of oil have increased almost exponentially in the past 5 years. This sharp rise in daily costs has also led to a new urgency from operators to find more-reliable and -efficient ways of doing business. Shock and vibration (S&V) are the leading causes of failure for measurement-while-drilling (MWD) and rotary-steerable systems today. These failures have a major impact on operators and service companies, costing millions of dollars in repairs and hours of rig time. To better understand downhole dynamics, a wide variety of service companies now offer lateral, axial, and transverse-shock measurements, along with downhole rev/min (RPM) readings. In the best case, these measurements offer a reactive method of drilling, and in the worst case, they provide no help in solving the problem or in preventing damage to the bottomhole assembly (BHA). For S&V measurements to be effective, operators and service companies must work together to create a comprehensive process that includes each phase of drilling—planning, execution, and evaluation. An S&V standard combined with increased client awareness and education has allowed a new level of success to be achieved at the rigsite. Now, S&V issues at the rig can be identified in real time and monitored remotely from an operations-support center. This communication structure, coupled with prejob planning and modeling and the capture of post-run lessons learned, can be used to offer solutions when problems arise, thereby preventing damage to the BHA, reducing rig non-productive time (NPT), and improving the rate of penetration (ROP).

Health physics activities in support of the thermal shield removal/disposal and core support barrel repair at the St. Lucie Nuclear Power Plant.

The health physics activities related to the removal and disposal of a thermal shield at a nuclear power plant and subsequent repairs to the core support barrel required increased planning relative to a normal refueling/maintenance outage. The repair of the core support barrel was a "first" in the nuclear power industry. Pre-job planning was of great concern because of extremely high radiation levels associated with the irradiated stainless steel thermal shield and core support barrel. ALARA techniques used in the preparation of the thermal shield for removal and shipment to the disposal site are discussed.