Qiu, Kaibin (Schlumberger) | Gonzalez Felgueroso, Julio (Repsol) | Lalinde, Gabino (Akakus Oil Operations Libya) | Coste, Bernard Jean (Total Yemen) | Naas, Abdulmajid (Repsol YPF) | Fuller, John (Schlumberger)
Drilling highly deviated or horizontal wells can be prone to instability problems. This paper describes a case in Libya on which significant difficulties were encountered during drilling the first horizontal development well in a field in Murzuq basin. The first two branches of the well were lost due to severe instability problems.
A comprehensive geomechanics study was carried out to understand the causes of the wellbore failure and to improve drilling design and drilling performance on further development wells in the field. The study specifically included:
The analysis identified the cause of wellbore instability, as being inadequate mud weight while drilling the overlying shale formation in the deviation build-up section. The design of the second horizontal well was optimized based on this study. The well was drilled successfully without problems and, in fact, ahead of drilling schedule. This case demonstrated that a comprehensive geomechanics analysis can greatly improve drilling performance and reduce drilling costs.
Horizontal wells can increase production rates and ultimate recovery, and reduce the number of platforms or wells required to develop a reservoir. The geometry also helps to delay water or gas breakthrough, bypass environmentally sensitive areas and reduce stimulation costs.1 To achieve avoidance of water coning and delay of water breakthrough, Akakus Oil Operations started to drill the first horizontal development well H1 in a field in Libya in 2006. However, unexpected drilling difficulties were encountered and the first two branches of the well were lost. Prior to this project, quite a significant number of exploration and development vertical wells had been drilled in the same block without experiencing any major problem. A wellbore stability study was carried out to understand the cause of wellbore failure in the horizontal well, to optimize the drilling design and performance for the next horizontal development wells to be drilled in the same field.
This paper presents the results of a two-year comprehensive effort to design, test, and qualify third-generation rotary-shouldered connections (RSC) for 20,000 psi internal and 10,000 psi external pressure service. ISO13679 testing methodologies for casing and tubing were modified to evaluate the RSC pressure capability. Results from comprehensive finite element modeling and extensive laboratory testing designed to reproduce the harsh, aggressive loading modes and high pressures encountered in field use are presented.
The result of this program is a RSC that incorporates a double-start thread form to reduce the number of revolutions to assemble the connection by 50 percent reducing trip time. The thread form also provides a unique dual-radius thread root that offers a step change improvement in fatigue resistance. A metal-to-metal seal provides pressure integrity.
In addition to providing a 20,000 psi internal and 10,000 psi external pressure rating, the new connections provide increased mechanical and hydraulic performance compared to second generation high torque connections while also providing fatigue performance greater than standard API connections.
The use of hole opening tools in conjunction with Rotary Steerable Systems (RSS) has increased dramatically in the past few years. Although excellent performance has been delivered with the mainstream commercial tools, alternate options have been developed to enable an RSS to drill the pilot hole in conjunction with a string tool to open the hole in a single run.
The most popular current option involves a weight or hydraulic activated underreamer. However, fixed blade, multi-diameter reaming tools have recently been developed for use within Rotary Steerable (RS) assemblies:
Several distinct applications are documented where these fixed bladed solutions, in combination with both Push and Point RS tools, have proven extremely successful. This has provided greater flexibility with regard to tool selection and well planning options, delivering lower cost per foot in RS projects. Case studies are presented from the Far East, Norway, and the Gulf of Mexico.
Re-entry drilling represents a significant part of the current and future drilling activities worldwide and particular in the Russian Federation. Enormous funds of old oil and gas wells drilled in the last century are un-active. Economical demand positions the sidetracking activities with a very promising future of the drilling activities. A Russian oil company, famous for successful development of challenging ERD projects at Sakhalin Island, has around 1000 of oil wells drilled between 1950 and 1980 with most of them currently idle.
This paper presents a study of the feasibility of drilling horizontal extended reach sidetracks to increase oil production from these mature oilfields. Its main objective is to evaluate technical and economical aspects associated with drilling horizontal re-entries from already existing old oil well stocks. The objectives of the paper are: Evaluation of the economical attractiveness of such a project; Candidate selections; Drilling engineering design of the wells; Evaluation and selection of contractors for provision of appropriate re-entry equipment such as whip stocks, scrapers, mills, bi-centered bits, etc; Subsequent coordination between proposed and involved parties; Evaluation of the well placement approach implication.
With the successful development of the re-entry drilling project the following potential benefits are realized at this stage: Oil production increase through the old portfolio of wells revival; High quality technical project development; Low tier market development for the known to be a high tier market ground at Sakhalin island; Revenue sustention for known to be a cyclical and season dependent market.
Introduction, Scope of the Project
There is a clear need for the extraction of more oil and gas worldwide. Demand is increasing continuously and the oil industry needs to provide solutions to meet expectations. In this specific case a Russian oil company sits on 1000 wells on the Sakhalin Island which are un-active. Reserves are proven, but the wells have been drilled over a period of half a century. Technology has advanced a lot in the past decades. Implementation of new technology into these mature oilfields would increase production significantly. One of these technologies is to drill extended reach sidetracks. This paper presents an identification of the client's drivers, evaluates capabilities of available equipment and personnel, identifies shortfalls and improvements needed and finally presents a possible design for the sidetracks to successfully meet the objectives of this campaign.
Drivers for the Study
The Russian client is one of the biggest clients in Russia. A strong business relationship has been established with a Western DD/MWD service company. Since 2003 there has been continuous collaboration resulting in some spectacular extended reach wells. A total of 17 wells have been drilled so far in the North of Sakhalin Island. Relations are excellent, well established business and operating processes have created a high level of trust. All in all this Russian client owns about 2000 production wells and 1000 injection wells on the island.
Iversen, Fionn Petter (Intl Research Inst of Stavanger) | Cayeux, Eric (Intl Research Inst of Stavanger) | Dvergsnes, Erik Wolden (Intl Research Inst of Stavanger) | Ervik, Ragna (Intl Research Inst of Stavanger) | Byrkjeland, Martin (Intl Research Inst of Stavanger) | Welmer, Morten (National Oilwell Varco) | Torsvoll, Arne (Statoil ASA) | Balov, Mohsen Karimi (Statoil ASA) | Haugstad, Eilert (Statoil ASA) | Merlo, Antonino (Eni Agip SpA)
A new drilling control system enhancement for real-time optimization and automation control has been installed on the rig and tested in passive mode in preparation for a full-scale drilling test. The testing has been performed on the Statfjord C platform in the Norwegian sector of the North Sea.
The aim of the field test is to demonstrate that the incorporation of real time calibrated process models in drilling control can make the drilling process more reliable, increase efficiency, and improve safety for the drilling crew and with regards to control of the drilling process.
The system, described previously, performs continuous optimization of operational parameters using calibrated dynamic process models. Safe operational windows are calculated, and operational sequences are automatically optimized through forward model simulations. The results are applied to machine control in real-time, providing process safe-guards and increasing process efficiency.
A thorough description of the preparations and passive testing is given. The final test results are to be evaluated based on success criteria developed prior to the test in cooperation with field operator and drilling contractors. The implications for the work organization are also discussed, particularly in relation to control of data input, decision making and responsibility.
This technology will allow for direct integration of the know-how and best current practices into the drilling control system. Automated procedures and tests are to provide improved control of well conditions. Direct integration of process models shall enable safe optimization in the short time scale. And coupling the system to remote input will enable optimization in the long time scale, while built-in monitoring and diagnostics may ensure safe application of optimised parameters.
The influence of improved technologies and the latest operational developments has lead to a significant impact in the arena of coiled tubing drilling operations. These influences are also making themselves known in the underbalanced coiled tubing drilling sector. Sidetracking operations have traditionally utilized a philosophy dominated by threaded tubular drilling conveyance methods; however, with the growth of coiled tubing drilling applications in recent years, coiled tubing deployed bottomhole assemblies for sidetracking a well are beginning to gain acceptance as a standard practice.
A major advantage of a coiled tubing deployed exit system is the ability to mill a window in the casing in a restricted wellbore environment. The whipstock can be deployed in a live-well condition without the necessity of removing the completion equipment thus eliminating the requirement for a workover rig and negating the need for kill weight fluids. The systems can be deployed on either electric wireline or coiled tubing making them ideally suited for restricted bore access and allowing the window to be milled below the completion.
The discussion will include a comprehensive overview utilizing a new whipstock system with the conveyance method of coiled tubing and electric wireline in order to create a casing window. The overview will also communicate general practices and tool selection criteria with the case histories representative of the placement of the whipstock with coiled tubing and the window milling being performed with coiled tubing workover motors. The case histories will detail two runs of the new exit system, the first in the North Sea and the second in the Middle East. Both case histories will show the economic benefits of utilizing live well intervention deployment methods for whipstock placement as well as the rig cost savings of utilizing coiled tubing deployed mills and motors for delivering a casing window.
Kikeh Field is located 120 km from Labuan in offshore Sabah Malaysia. The field, with 1330 m water depth, is the first deepwater development in Malaysia and consists of subsea and SPAR development wells.
The West Setia is a non-propelled Semi-Submersible Drilling Tender being used for SPAR development activities. The Drilling Tender utilizes six stability columns supported by a twin-hull configuration. However, the derrick and partial rig package still sits on the SPAR (or platform deck) to carry out drilling and completion operations.
The completion program covers not only standard scope of installation, i.e. lower, middle and upper completion, but also includes displacing fluid with nitrogen for riser dewatering and well clean up and testing. Several logging operations also were identified as tasks to be delivered during completion operations.
Considering the wide scope of completion work outlined in the program, a detailed work assessment was conducted focusing on areas where offline activities could be conducted safely and efficiently. As a result of the assessment, at least seven completion-related activities were identified.
During the first batch of SPAR completions which involved five wells, the result showed that the following activities were successfully completed offline, allowing the rig to be utilized for critical path operations:
This paper will describe in detail each of the operations involved, discuss rig capabilities and limits, and explain the challenges, safety considerations and lessons learned from the project as well as the time savings and value created from each of the activities.
Heightened levels of industry activity have put an increased focus on all types of training, particularly in the critical area of well control. The development of competent personnel capable of recognizing, avoiding and mitigating well control situations requires industry-developed systems capable of establishing necessary training standards and quality assurance programs that monitor training provider performance, both essential elements for ensuring proper skills development through fit-for-purpose training.
The Well Control Accreditation Program (WellCAP) operated by the International Association of Drilling Contractors (IADC) is designed to provide the drilling industry the building blocks for a comprehensive "well control culture?? beginning at the floorhand level and continuing to the most seasoned drilling personnel.
Rig workers are introduced to the basics of well control equipment at the Introductory Level. Simulator exercises provide a higher level of practical knowledge at the Fundamental Level, recommended for Derrickmen, Assistant Drillers and Drillers. More complex simulator exercises and calculations are a component of the Supervisory Level, designed for drillers, toolpushers, superintendents and drilling foremen. WellCAP Plus is the latest addition to IADC's WellCAP system, which introduces a new learning model focus on highly experienced employees.
Since the program was first implemented in 1995, WellCAP's curriculum offerings have evolved steadily to keep abreast of industry needs.
By reminiscing about new drilling rig construction for the last 15 years, this paper proposes a change of thinking in reducing both cost and risk through the application of lessons learned. Every individual who has been involved in building rigs carries their own lessons learned forward, and they naturally apply them to their next construction project. Historically, these collective lessons have not been proactively focused for the good of the industry. Therefore, the intent of this paper is to draw upon the concurrent themes of these lessons learned and, in turn, propose industry-wide solutions when dealing with new-rig construction.
The group with the broadest exposure to execution challenges, and the subsequent source of the information within this paper, can be found with the suppliers, installers, and integrators of the equipment and controls on new-build rigs. In our most recent construction cycle, the introduction and application of the most successful past-era behaviors has removed considerable risk from the emerging processes. The emerging processes that have been developed are the product of increases in complexity and the subsequent integration challenge that comes from numerous control systems. However, as it is known, these control systems are expected to work as one harmonious drilling machine, and historically this has not been the case! Impressive early results have shown marked improvements with the implementation of complete standard rig designs. These results have reduced the overall risk, and in some cases, they have shown how the innovative utilization of simulators early in the process to try and face construction woes, prior to the actual construction process, can avoid hitting a bottleneck in the process.
Sand control decisions are often made based on a deterministically predicted Safe Drawdown Pressure (SDP) without proper regard to the amount of uncertainty associated with the value of SDP. These uncertainties can be large when planning a Drillstem Test (DST) for a
deepwater exploration well. On one hand, predicting too low of a SDP for a DST can result in unnecessary sand control. On the other hand, predicting too high of a SDP can lead to sanding during the test, which can cause numerous problems and ultimately cost much more than a sand control installation. Thus, a probabilistic study is warranted to quantify the expected sanding risk through a SDP probability profile, which can be used to estimate the risked expected value of a decision to install sand control or not.
In this study, data from 12 offset wells in nearby blocks from an Offshore Nigeria exploration well were reviewed. First, a regional geomechanical model (in-situ stress, pore pressure and rock mechanical properties) was calibrated and validated based on offset data. The calibrated geomechanical model was used with a sanding prediction model and was calibrated and validated based on offset
DST and sand control data. Next, a statistical analysis of regional in-situ stress, sand pressure and rock properties for different sand intervals was performed to generate the necessary Probability Distribution Functions (PDF) and used as inputs to a SDP Monte Carlo simulation. And finally, a deterministic approach was also used to predict SDP. A comparison of Monte Carlo simulated SDP distribution and the deterministically predicted one from offset wells indicates consistent results. The SDP PDF allows estimation of the expected values for installing sand control or not and improves judgments of the true cost of obtaining the DST information.
Introduction to Sanding Potential Prediction
A sanding potential prediction generally involves the estimation of a deterministic SDP. When this SDP is exceeded, either during a well test, a DST or during production, the probability of sand production increases. Numerous empirical, analytical, and numerical models
were proposed to predict the onset of sand production. For a brief review of those models and their strengths and weaknesses, readers can refer to a recent publication by Qiu et al . Among those published models, analytical models seem to have gained popularity in the industry possibly because they can be implemented and calibrated more easily compared to numerical models while still capturing the mechanism of sand production. Whether an analytical or numerical method is used, one critical step is to calibrate the model using available sanding or no sanding historical data before applying it to sanding potential prediction for a planned well. For this paper, an
in-house analytical sanding onset prediction model was used. This model takes into account the effects of wellbore deviation, perforation orientation, and uses Hollow Cylinder Strength (HCS) instead of Uniaxial Compressive Strength (UCS) to reduce an apparent
conservative rock strength bias. Numerous studies were performed on Chevron wells worldwide using this model and it works well especially after calibrating it with sand (or no sand) production data .