After an operator confirmed wellbore integrity failure in a well located on a small platform, a coiled tubing (CT) catenary intervention was urgently required. However, the production facilities of the platform were not authorized to operate, which represented an impediment to receive returns from the wellbore. This paper documents the analysis and implementation of nonconventional flowback methods and the actions taken to perform the intervention using a state-of-the-art fly-by-wire CT catenary package in a setup that had never used before in this field.
After a shut-in period, the subject well faced integrity issues that could end in an uncontrolled situation. To remediate this situation, milling and plug-setting runs were designed using a catenary system with a fly-by-wire CT unit set for first time completely on the vessel and leaving only the injector head on the platform. To address the flowback limitation, technical and economical assessments were performed on three options: using slope barges to receive fluids in storage tanks, setting conventional flowback equipment on board the catenary vessel, or using the gas injection pipeline available on the platform.
After analyzing each alternative, the options to use slope barges and flowback equipment on the vessel were discarded after confirming that they represented an additional risk and generated higher costs for their implementation. The use of the gas injection pipeline involved the modification of many resources on land and at the offshore facilities, and a detailed plan was needed to utilize the lines in a different way from their initial design. Additionally, weather conditions played a major role during the job execution. Consequently, a special focus was placed on elaborating contingency plans to address emergencies during the operation taking into account that the method implied handling hydrocarbons at surface under uncommon situations. The coordination and collaboration in the operation enabled the operator to achieve the expected results, recovering the wellbore integrity in a cost-effective way, while also eliminating the exposure of additional vessels or sophisticated equipment on location.
The paper presents the large amount of information that was amassed during the implementation of the solution, which could be used by other locations facing similar conditions where conventional production facilities cannot be used during well interventions. The document also includes contingency plans for every stage of the project, safety measurements, lessons learned, and details of the modifications done to the gas injection system and the CT equipment.
A truly optimized completion requires a wide range of understanding and activities. Starting with a thorough understanding of the reservoir, each completion element must be fully addressed from connecting to the reservoir, to enhancing the reservoir through proper treatments, to conducting hydrocarbons to surface for optimal efficiency. By considering the cause-and-effect interactions between these activities, each individual process can be designed and performed better, ultimately delivering the best overall solution. This overarching philosophy is also fully applicable to perforated completions.
Providing a perforating solution that is truly optimized for the reservoir is challenging, requiring advanced laboratory testing capabilities, reservoir specific products and systems, robust analysis and modeling tools, and a thorough process to insure solutions are designed, executed, and reviewed for continuous improvement and optimization. Recent advances in in-situ perforation testing techniques provide significant insights into dynamic events during perforating as well as enabling more reservoir specific equipment designs. Furthermore, state-of-the-art computational models complement testing methods by correlating dynamic perforating events and inflow analysis to actual productivity. Numeric modeling techniques also allow results from lab testing to be better translated into field scale environments. And finally, rigorous procedures can be followed to practice this process across a wide variety of completion types to provide well optimized perforated completions.
This study will detail the techniques used to employ the philosophy, and multiple case histories of such applications with results and lessons learned. In these cases, a comprehensive consideration of the overall completion was critical in optimizing the perforating process. The use of laboratory testing, customized products and systems, integrated modeling and analysis tools, and a disciplined process have led to the successful application of this scientifically engineered philosophy. This unique perforating philosophy is also aimed towards integration with other completion methods like hydraulic fracturing & stimulation, sand control and management and above all, enhancing reservoir productivity.
Outputs from geological and geophysical applications are the major drivers for upstream prospect generation and field development. The current generation of applications can quickly produce a massive amount of intermediate data based on the iterative and interactive workflows. One major challenge for large organizations, with many disparate software systems and a large user base, is maintaining a clean and optimized data environment. Data management plays a key role in the delivery of accurate and efficient interpretation results to improve the decision making and exploration success. This case study shares the authors’ experience in leading corporate and project-based geoscience data management activities for several industry-leading applications.
The first activity was the data cleaning, standardization, and consolidation of over a 100 repositories of multiuser project-based application databases that had accumulated over 20 years. The objective for each step (data cleaning, standardization, and consolidation) was clearly defined and the processes have been implemented using best technologies. Automatic procedures have been implemented to optimize the master and interpretation data. In addition, this paper addresses the application of knowledge management methodologies, to transform existing geoscience interpretation workflows into a knowledge-based asset management system. We present the business drivers for each activity, challenges faced, and the approach adopted to resolve those challenges.
During the data management activity, many of the project databases need to remain active for ongoing well planning, monitoring, and geosteering, which make data management more challenging. New naming conventions were also established and enforced. These provided a larger than expected benefit to the users, in terms of data accuracy and availability. One sizeable operational database achieved around 55% clean up from projects’ archival and deletion. It it because projects are either not active anymore or merged with other projects. Geophysical interpretation has become an iterative, interactive, and resource intensive process. It generates massive amounts of maps and volume-based attribute data, resulting in significantly increased storage utilization and data complexity. The major challenges were to identify and extract the best available interpretation version, streamline the data flow, and leverage existing corporate knowledge. All challenges were tackled successfully, bringing a huge benefit to the organization. The creation of new processes, awareness, standards enforcement, and automation guided geoscientists toward the best data management practices. Benefits in reducing operational costs and improving productivity have been realized.
Innovative approaches utilized in our activities include knowledge management methodologies, automatic procedures implementation for data management and optimization. In addition, a continuous reporting mechanism was established to assure complete control and monitoring of data growth. This paper also provides a roadmap that can be applied to similar data management activities in the geoscience domain. Data management has been transformed into a continuous process, rather than a one-time task.
This research paper is aimed at explaining how information technology projects are effected by good risk management. Consequently, it can be used as reference for IS managers. It answers our concern of how risk management contributes to IT project success. Obviously, we investigated how project risk management effects IT projects, which is essential in various industrial activities. We looked into some estimates of the effects of risk management in IT projects. Our methodology approach showed how performance evaluation can be utilized to assess the impact of risk management on such projects.
The DCS (distributed control system) alarm system at Gathering Centers of Kuwait Oil Company was not functioning as required. DCS alarm system was generating high no. of alarms which was out of operator's alarm handling capacity. This was highlighted as one of the key contributing factors resulting in process upsets & incidents. A detailed investigation revealed lack of alarm management philosophy during design & operation stage as main cause of this poorly functioning system.
This paper shares field experience of analysis of DCS alarm system and explains main root causes which resulted in such poorly functioning alarm system at oil and gas gathering centers.It provides guidelines to carry out alarrm management exercise for improving DCSalarm system & for developing alarm management philosophy to implement and sustain efficient DCS alarm system.It also shares some of the actual alarm data and their analysis, which supports need of well-developed alarm management philosophy and continuous alarm management exercise for efficient DCS alarm system.
It was observed that majority of problems of alarm flood is contributed by selective alarm tags which generate huge number of alarms under category of frequent alarms, duplicate alarms and chattering alarms. The DCS alarms system improves significantly by resolving these alarms. It was concluded that a well-developed Alarm Management Philosophy and execution of well-defined alarm management approach is essential to ensure proper configuration of alarms starting from project stage and sustain it during operation stage of facility.
The paper provides guideline to develop and implement Alarm Management Philosophy and justifies need for Alarm management philosophy to ensure implementation of efficient DCS alarm system and thereby achieving safe and smooth operation of facility.
Al-Houti, Naser (Kuwait Oil Company) | Al-Othman, Mohammad (Kuwait Oil Company) | Al-Qassar, Khalid (Kuwait Oil Company) | Al-Ebrahim, Ahmed (Kuwait Oil Company) | Matar, Khaled (Halliburton) | Al Hamad, Abdulla (Halliburton)
This paper presents the application of a unique gelling system for perforation shut-off operations that can help reduce operational time by 50% and can also be used as an effective water- and gas-migration control agent. The system combines a conformance sealant (based on an organically crosslinked polymer) with non-cementious particulates. The particulates provide leak-off control, which leads to shallow matrix penetration of the sealant. The filtrate from the leakoff is thermally activated and, as a result, forms a three-dimensional (3-D) gel structure that effectively seals the targeted interval after exposure to the bottomhole temperature (BHT).
The traditional method for recompleting wells into newer layers, after the current producing zones have reached their economic limit, involves several steps. The first step is to squeeze off the existing unwanted perforations using cement, drill out the cement across the perforations, and then pressure test the squeezed zones to help ensure an effective perforation seal has been achieved. The new zones are then perforated and completed for production. The entire operation can require four or more days of rig time, depending on the success of the cement squeeze. In cases of cement failure, the required time can extend to over one week. Common challenges associated with cement-squeeze operations include leaky perforations, fluid migration (gas or liquid) behind the pipe, or compromises in the completion. Attempts to remediate these issues must be repeated until all objectives are met.
The new perforation plugging system can be bullheaded into the well (spotted at a desired location in the wellbore), allowing for easy placement and calculation of the treatment volume. The limited and controlled leakoff into the matrix during the squeeze results in a controlled depth of invasion, which allows for future re-perforation of hydrocarbon-producing zones. The system can be easily washed out of the wellbore, unlike cement, which must be drilled out. The temperature range of the particle-gel system is 60 to 350°F, which makes it versatile.
To date, more than 500 operations have been performed with this system globally. This paper presents the results obtained from laboratory evaluations, the methodology of the treatment designs, and four case histories from Kuwait. A salient case is the successful use of the sealant/particulate system, resulting in shutting off all perforations after six failed cement-squeeze operations.
The prospect of reducing the required time to perform remedial cement-squeeze operations by 50%, as well as the ability to repair casing leaks and seal off thief zones, make this sealant/particulate system a valuable alternative to standard cement-squeeze operations.
With growing regulatory requirements focusing on well safety and risk mitigating barriers, there is an increased requirement for surface-controlled subsurface safety valves (SCSSVs). Most SCSSV's provide well protection by means of a normally closed flapper-type closure mechanism that prohibits deployment of capillary or through-tubing based solutions which would not allow the flapper to fully close in the event of an ESD.
Operators desire cost effective rig-less deployment of capillary-based solution(s) to increase production and or reconnect a non-functional hydraulic control system. To date flow actuated subsurface controlled safety valves have provided a solution for loss of hydraulic control of a tubing-mounted SCSS; however, these valves are becoming less desired due to decreasing acceptance from regulatory agencies. Additionally, traditional post-completion chemical injection systems beyond a SCSSV have not been possible for continuous well-stimulant injection, nor has a solution for post-completion gage monitoring past a SCSSV been achieved.
This paper discusses technology enabling rig-less ability to reconnect a hydraulic system to a SCSSV or Safety Valve Landing Nipple by deploying a thru-tubing capillary based system inside the SCSSV / SVLN while maintaining functionality of the safety valve. In addition this solution can be utilized for continual injection of chemicals directly below the SCSSV and onwards to production zone depths. Further a downhole gage can be installed directly below the SCSSV and up to depths of 20,000 feet. Each of these functional characteristics can only be realized though the introduction of this novel capillary based solution, which maintains the "fail-safe" closure capability ensuring well control against a catastrophic event were to occurring at the surface or below.
A newly-developed 3 ½-in. coiled tubing telemetry (CTT) system has been used for the real-time operational optimization of such coiled tubing (CT) applications as milling, cleanout, logging, and perforation, in an offshore multi-well campaign in Norway.
The CTT system consists of surface hardware and software, a dual-purpose wire inside the carrying CT, and the multi-function bottom hole assembly (BHA). The wire transmits electrical power from surface to the downhole sensors located in the BHA and the downhole data from these sensors to surface. The BHA, designed in one of three sizes (i.e., 2 ⅛-, 2 ⅞-, and 3 ½-in.), contains a casing collar locator (CCL) and two pressure and temperature transducers that are capable to measure downhole data inside and outside the BHA. One of the main advantages of the CTT system is its versatility. For instance, switching between applications is as simple as only changing a certain part of the BHA. This reduces the need to rig-up and rig-down and leads to operational time and cost savings to operators. Another main advantage stems from its real-time downhole data certainty, as the CT field crew can immediately make decisions based on dynamic downhole events.
A few papers have been published recently regarding a similar 2 ⅛ and 2 ⅞-in. CTT systems (SPE-174850, IPTC-18294, SPE-179101, and SPE-183026). In this paper, several case studies are presented for the 3 ½-in. CTT system for the first time. For instance, in the first well, the CTT system helped remove approximately 26,500 lb of scale through a complex wiper trip schedule, effectively preparing the well for re-completion by the main rig. In the second well, the CTT system helped pull all shallow and deep plugs and perforate three intervals in one run. In the third well, the CTT system helped clean out the well, set a plug, and re-perforate it. In addition to successfully performing all these operations, several other benefits resulted due to the real-time downhole data monitoring provided by the CTT system. For instance, the fluid friction reducer (used for reducing the fluid frictional pressure drop) was effectively used at volumes of 70-75% lower than those recommended when the CTT system is not used. Also, all these operations were performed without the need to mobilize most of the wireline and tractor equipment and crew, saving an estimated time per well of six days of wireline logistics and work.
The paper briefly describes the 3 ½-in. CTT system and discusses the data acquired during these field operations. The system performance and operational benefits confirmed are presented. These findings outline the versatility of the 3 ½-in. CTT system, the predictability of successful operations resulting from using this system, and the cost and time savings to operators.
ERD wells are commonly associated with major challenges for installation of casing and liner strings. These wells typically present high torque and drag parameters that jeopardize getting strings to total depth.
In an attempt to optimize production, a major oil company in Angola decided to re-enter the study well in early 2016. A sidetrack was opened in the 9 5/8-in. casing, and drilling continued in the 8 ½-in. hole and penetrated the target zone in the highest location. Then a 7-in. production liner was run.
To reach the target zone, 5,583 ft of 8 ½-in. hole was drilled and deviations varied from 45° to 87°. This trajectory was a challenge for subsequent running of 7-in. liner. Torque and drag (T&D) models showed liner rotation at total depth (TD) was not possible, and a surge model indicated likelihood of mud losses while running the liner.
Liner hanger technologies became a very important phase of well construction, and service companies developed advanced liner hangers to overcome hostile well environments. In this case study, the short time available from the planning to execution phases and the current oil market conditions made it imperative that the right equipment, service, and technology were available in country. To achieve the ideal working parameters and get the liner to bottom, a thorough assessment needed to be performed to ensure risk mitigation.
This paper presents summarizes steps considered during planning for the 7-in. liner run including a detailed engineering analysis that enabled the operator to make the best decisions based on the available resources. The paper will also discuss lessons learned and best practices captured during the job that will be used for subsequent liners in similar wells.
The case study well was planned as a sidetrack from an existing well that had been shut in because of low performance. The main well had been drilled and completed as a single gravel pack in 2007. The objective of the sidetrack was to penetrate the reservoir organized complex in the structurally highest location to access reserves and optimize production. A constrained initial production was estimated at 6035 BFPD.
An operations overview of the complete intervention is as follows: Set a 8 ½-in. whipstock in existing 9 5/8-in. casing at 8,400 ft and mill the window. Drill an 8 ½-in. hole section to 13,923 ft MD / 6,657 ft TVD. Run and cement 7-in. liner. Displace the hole with completion fluid. Perform cement bond logs and hand the well over to completion.
Set a 8 ½-in. whipstock in existing 9 5/8-in. casing at 8,400 ft and mill the window.
Drill an 8 ½-in. hole section to 13,923 ft MD / 6,657 ft TVD.
Run and cement 7-in. liner.
Displace the hole with completion fluid.
Perform cement bond logs and hand the well over to completion.
The 8 ½-in. hole was drilled as shown in Well trajectory for case-study well Geometric features of case-study well
Measured depth at whipstock point 8,400 ft TVD at whipstock point 5,279 ft Deviation at whipstock point 78.25° Length of 8 ½-in. hole 5,583 ft Measured depth at TD of 8 ½-in. hole 13,983 ft TVD at 8 ½-in. hole TD 6,695 ft Maximum deviation in 8 ½-in. open hole 86.9° Maximum dogleg severity in 8 ½-in. open hole 5.21°/100 ft at 8,933 ft MD
Well trajectory for case-study well
Geometric features of case-study well
The operator and the liner hanger service company used proprietary simulation tools during the planning phase to predict possible issues for running the liner. The simulation considered main aspects, such as well trajectory and the influence of the whipstock installed in the 9 5/8-in. casing. All analyses were performed and maximum working parameters were defined and included in the well program. The operator also considered possible limitations that using standard equipment available in country might impose on well life. The final management decision was to proceed with the plan presented.
The paper addresses the use of steel chains in a lazy wave configured flexible riser system to provide an alternative flexible riser configuration for use in challenging environments including large vessel offsets and motions, and large ranges of riser internal fluid properties. While the compliant nature of flexible pipe provides excellent fatigue and strength resistance, flexible risers typically experience larger deflections when compared with rigid risers, which results in greater challenges managing interference issues with adjacent structures. Different lengths and variable masses of chain are installed at locations along the hog bend of the flexible riser configuration. The arrangement of the chain masses, length and positioning along the line are developed to primarily prevent contact with the seabed and the hull of the FPSO when a range of heavy and light internal fluids are considered. A number of weighted steel chain configurations are evaluated and presented through an analytical case study in order to demonstrate the benefits of this approach for a typical generic shallow water application FPSO system. Installation and hardware design aspects are additional requirements that may need to be addressed in further assessments.
Through the in-place case study, comparisons are made between the performance of the flexible riser system with and without the weighted steel chains. Global finite element models are developed to simulate the performance of the different flexible riser configurations when subject to a range of loading scenarios covering large FPSO offsets, harsh environmental conditions and a range of riser internal fluid densities. Performance criteria of the flexible riser such as tensile loading, curvature and motion envelopes are presented to show the improvements derived though optimisation of the chains. It is also demonstrated that the chain section that extends along the seabed helps to reduce the transverse displacement and "lateral walking" thus reducing the risk of clashing with adjacent structures and changes in line lay azimuth under strong transverse current loading. The cost effectiveness of the chain weighted flexible is also compared to other solutions considering new and retro-fit applications. This work demonstrates that an improved and cost effective solution is developed to provide an acceptable flexible riser dynamic response for the range of operational fluid densities that may be experienced in its operational lifetime.