The oil industry in the UAE is striving to advance both onshore and offshore operations to address technological challenges that will allow for increased oil production in a safe and efficient manner. Offshore, artificial islands are being built for the purpose of accommodating up to 300 wellheads on a single island, with the wells themselves comprising multiple, extended-reach horizontal laterals. These ground breaking projects present new and exciting challenges for coiled tubing (CT) interventions, which require extensive planning and the use of innovative technologies.
Specific challenges were identified during the design phase of intervening on a trilateral, extended reach well and applying several technologies enabled us to overcome these challenges to allow successful execution of a stimulation treatment on the well. Techniques used included accessibility modelling and CT string selection to achieve maximum reach.
The methodology used and the testing conducted were designed to ensure that the multicomponent CT bottomhole assembly (BHA) allowed for selective engagement of each lateral and subsequent horizontal accessibility of each extended-reach lateral. Operations were performed in the context of the completion restrictions, diameter of the openhole and cased-hole laterals, and the requirement to pump large volume acid treatments. Each of these factors added a layer of complexity to the final CT BHA selection and setup, which had to operate within a limited range of activation pressures and rates.
Finally, the lessons learned during the execution phase have been captured and recommendations formulated for moving forward with CT intervention in similar types of multilateral and extended reach wells. These lessons contribute to subsequent studies of maximum reservoir contact wells and form the basis of future development and intervention plans for the offshore and islands projects in the UAE.
With the current government environmental directives in the Gulf of Mexico (GoM), operators are challenged to ensure that idle iron wells are correctly handled to meet regulatory requirements in the full abandonment of the wells and their platform structures. With this, there is a need to remove existing production tubulars and set the required abandonment barriers before removing the offshore structure. Because of the current operational climate, there are many challenges that operators face in the GoM with regards to their ability to secure rig set equipment and personnel to effectively perform these operations in an economic manner.
This paper details an operational challenge of preparing for the temporary abandonment of an operator's GoM compliant tower structure, where an existing wellbore had been shut in with an annulus containing sustained casing pressure up to 3,000 psi. To facilitate the operational work scope, a hydraulic workover (HWO) rig was selected to be installed to the compliant tower structure, which allowed for the successful removal of the completion and preparation for the impending platform abandonment process, all while simultaneously working under the operational constraints of a producing facility.
This publication shows that through the application of detailed engineering and operational programming, the challenges of adapting existing equipment, restrictions on available space, reduced deck load capacity, along with crane limitations, all before HWO operations in an offshore environment with the potential for severe weather on a compliant tower, were safely overcome while performing the operations.
Well intervention is a critical aspect of managing brownfield assets as operators seek to optimize hydrocarbon recovery and perform maintenance work to ensure wellbore integrity. The costs of traditional workover methods and technologies, specifically in an offshore environment, can create economic barriers to the number and types of interventions that are completed in a declining field. Light well intervention technology is considered a cost effective alternative to performing rig interventions on aging subsea wells.
Operators and service providers continually seek to develop technologies and procedures that mitigate economic risk when working on these mature production wellbores. One revolution that has been in development for the past few decades involves using conventional slickline and electric line to perform light well interventions without the requirement of an offshore drilling or workover rig. This process uses a light well intervention vessel (LWIV) complete with a moonpool located mid-deck for open-sea access, a riserless pressure control package typically involving remotely operated vehicles (ROVs), and a combination of conventional slickline and electric line intervention packages. Interventions using this technology adaptation were primarily developed for the North Sea and Gulf of Mexico regions and have been widely used in those regions. However, after several years of planning, the technology has now been used for the first time to rework several wells for an operator off the east coast of Canada.
Light, riserless, well intervention technologies have been deployed in three individual wellbores offshore Canada. Multiple services were required in each of these three wellbores. Conventional slickline operations were run to prepare each of wellbores, with the retrieval of crown plugs and conventional drift runs. Operations then switched to electric line services to perform diagnostic runs followed by remedial intervention services. Once the electric line services were completed, slickline services were used for safety valve isolations and gas lift remedial work and then returning the newly configured wells back to production mode. The use of the LWIV provided the operator with an efficient intervention technique to evaluate and potentially improve well performance.
Microbial influenced corrosion (MIC) has been implicated in few corrosion-related challenges in the well service industry in the past. Recently, the industry is observing an influx of MIC-related equipment damage. This upsurge of MIC conincides with a switch to unconventional water sources. As fresh water for fracturing operations and well interventions becomes less available, operators are forced to use alternative water sources such as recycled flow-back water, produced water, and even ‘grey water’ from wastewater treatment plants. In some instances, recycled water is sold from one operator to another for operations on other pads. Regardless of the water source for a particular well treatment operation, the same water-hauling equipment and tanks are used for successive hydraulic fracturing operations.
This ‘communal’ use of water hauling and temporary water storage equipment is an ideal situation for bacteria to move from one water repository to another. Even if the water source used to supply water for oilfield operations is free from harmful bacteria, it may still become contaminated - in transport or temporary storage vessels - before it is pumped downhole.
This paper is an overview of premature coil tubing and other well servicing equipment failures and pumping equipment damage that is related to MIC. Metallurgical, chemical and microbial analysis of the scale as well as representative water samples have been conducted to determine if the corrosion was the result of sulfur-reducing bacteria (SRB) or merely pitting common to oil field equipment from pumping hydrochloric acid and other corrosive fluids. This paper will explore the potential source(s) of the bacteria, the impact to the equipment that was exposed to the bacteria, as well as what is being done to mitigate the problem.
Li, Li (Shell) | Zhi, Guo Hong (Southwest Petroleum University, Schlumberger) | Millan, Hilarion (Shell) | Qiang, Zhang (PetroChina) | Tao, Zhang (Schlumberger) | Lei, Cui (Schlumberger) | Sheng, Li Yin (Schlumberger)
Changbei gas field is on the north edge of the Mauwusu desert in the Ordos basin in north-central China. The game-changing dual-lateral well concept is used in this tight gas reservoir. The typical well completion is kicked off at about 1700 m, and the hole is built to an inclination of 85° at the top of the reservoir with the 12¼-in. section. The first leg of the 8½-in. reservoir section is drilled for 2000 m. The second leg is drilled with an openhole sidetrack from leg 1. More openhole sidetracks are drilled from legs 1 and 2 if unstable intervals are penetrated. Upon reaching total depth (TD), a 7-in. slotted liner is run to protect any unstable claystone intervals.
As part of the well and reservoir surveillance activities and with the aim of improved understanding of the reservoir and well behavior, production logging is required to obtain the gas-contribution profile along the horizontal wellbore; the profile is used to confirm the size of the sand bar, facies distribution, wellbore condition, and production contribution from each leg. Previous attempts with wheel-driven tractors and conventional production logging tools (PLTs) were unsuccessful because most of the PLT runs encountered bad downhole conditions, such as water/mudcake, which led to failure of the tractors and PLT centralizers. The mudcake and debris could not be cleaned from wellbores, even though the wells had been produced at high rate.
To collect needed data, an advanced PLT consisting of an array of minispinners and optical and electrical holdup sensors was conveyed by an electrically powered tractor operating on the inchworm principle to successfully log a long-reach multilateral well. A workflow was followed to obtain wellbore accessibility and perform flow profile evaluation for the complex downhole conditions at Changbei. This was the first time a flow profile was obtained in Changbei block.
Coiled tubing (CT) monitoring tools are being utilized on a larger percentage of field jobs now as compared to the past. They are being used on both CT intervention and CT drilling operations. The objective of this paper is to demonstrate how a wall thickness measurement device can enhance and improve the calculations made by a CT fatigue algorithm.
Experimental work was done which shows how the wall thickness can vary depending on the pump rates, the fluid being pumped and the amount of tubing that is spooled on the reel. Reference four provides detailed information related to wall reduction in CT during pumping operations. Typically, fatigue models will utilize an estimated, nominal or minimal wall thickness to perform the fatigue calculations.
The amount of wall reduction in CT can vary greatly and as a CT string acquires fatigue, there is a chance that the estimated wall thickness may not reflect the actual wall thickness of the pipe. Recent modifications to fatigue tracking software allow the user to incorporate the real-time (or recorded) measured wall thickness into the fatigue calculations. This paper will discuss the experimental work, the modifications to the model, and case histories in which the wall thickness measurement device was used.
Calculating the CT fatigue using the measured wall thickness will increase the accuracy of the CT fatigue profile. This will allow CT service companies to operate at an increased efficiency. Operating companies will also benefit from this technology because there will be fewer fatigue failures at the well site due to the increased accuracy in the fatigue calculations.
Clients utilizing Coiled Tubing (CT) for straddle frac operations in multi-stage horizontal wells often encounter cement stringers preventing the frac bottomhole assembly (BHA) from reaching plug back total depth (PBTD) and the packer from sealing to the casing wall. This paper presents the learnings from a >90 well campaign of preparing for fracking operations using an electric line (e-line) milling and clean-out tool. The wells were mostly cemented, 4.5? liners with frac sleeves. This technique reduced frac preparation costs in the cemented wells by approximately 30%.
The common practice in Southeast Saskatchewan (SE Sask) is to perform a “well prep” operation prior to the frac equipment's arrival to the well site. A CT unit equipped with a rotating scraper/mill—and associated fluids—is used for the clean-out, adding to the logistical coordination and well costs. Fluid has several costs associated with it: the cost of the fluid/water itself, heating for winter operations, trucking and disposal. However, “well prep” is considered “cheap insurance” by most operators working in SE Sask compared to the potential costs of a waiting frac crew.
An operator in SE Sask has had success with an alternative clean-out solution to replace the use of fluid for well preps by introducing an e-line method consisting of an electric milling & clean-out tool with a casing collar locator (CCL). The mill is conveyed by e-line tractor and is equipped with a scraper mill to confirm the PBTD and ensure that there is no cement debris or sheath present that could negatively affect the frac operation. Various bailers can be added to collect the cement debris in the same run and ensure it is removed from the wellbore.
In combination with the clean-out service, a CCL is deployed and logged to surface to pinpoint the exact sleeve location to be referenced during the frac operation. This new, efficient clean-out solution has proved slightly more time-consuming (~3-5 hours) but yielded significant cost savings of approximately 30% per well of prep costs. These savings come from using e-line equipment, eliminating fluid costs and offering inherently safer operations with a low carbon footprint.
Moreover, the paper will discuss the future applicability of this ‘additional application’ for pre-logging runs as a means to reduce total completion costs in cemented wells. This is achieved by using the e-line milling tool as a pre-run for casing inspections or cement evaluation logging.
The Statfjord field was the first, and one of the largest, fields developed so far with Statoil as operator. The field was discovered by Mobil in 1974 and Statoil took over operatorship in 1987.
The field was developed with Statfjord A, B and C production platforms, which all have concrete gravity base structures incorporating storage cells. Statfjord A began production in 1979.
The field will remain in production until 2025 and possibilities to further expand the lifetime are being looked into.
One of the techniques that are being applied to rejuvenate some of the older wells is retrofit gas lift solutions.
In this paper detailed information on an Inverted Gas Lift System (IGLS) applied to a well on the Statfjord A platform will be presented. The IGLS solution included a solution to retain downhole safety valve functionality in the well and required qualification of a new type of coiled tubing material.
The following aspects of the project will be discussed in detail in this paper:
Background and objectives.
Method selection, planning and equipment qualification
Offshore operations for installation of the system
Follow up and results
When CT with internal pressure is bent around the reel or guide arch, and straightened in the injector chains, it experiences both plastic and elastic deformation. This results in internal residual stresses which cause bending moments and residual curvature. A “straightener” can be used to reverse bend the CT, which causes it to be fairly straight (no significant residual bend) but it still has significant residual stresses. Residual curvature and stresses decrease the buckling load (the CT is more prone to buckling) and cause safety issues if the CT is suddenly released. They can affect the fatigue life, but they are not in themselves an indicator of the amount of fatigue damage (as some have mistakenly thought). This paper presents the concepts and equations used to determine the residual curvature and residual stresses for a sequence of bending events, axial loadings, with internal pressure. These concepts and equations are then used to demonstrate the behavior of CT for several practical situations such as when it is run in and out of a well, and when it passes through a straightener.
Wiese, T. (ConocoPhillips Alaska Inc) | Yoakum, V. (ConocoPhillips Alaska Inc) | O'Dell, B. (ConocoPhillips Alaska Inc) | Loov, R. (Schlumberger) | Milazzo, B. (Schlumberger) | Nemec, J. (Schlumberger)
With approximately 1,200 wells and 47 developed drill sites in the Kuparuk River unit (KRU), North Slope, Alaska, a variety of well intervention services are required to keep wells in safe operating condition. Historically, conventional slickline and electric line services have performed a large portion of the non-rig diagnostics and repairs. With slickline operations generally limited to mechanical interventions and electric line required for depth-critical logging operations, both services are commonly required to complete a given well-work program. Because the intervention units are a shared resource, and the well-work schedule is priority based, there are often delays between slickline operations and the electric line diagnostics that follow.
Digital slickline services are being used in the KRU to improve overall well-work efficiency by completing intervention programs without the need for separate slickline and electric line services. Digital slickline services are being used to mechanically prepare wells for diagnostics, perform logging operations that would normally require electric line, and ready wells for repair without the need of additional service units. The enhancements linked to incorporating real-time surface readout data while performing mechanical interventions has reduced uncertainty and provided information for effective workover decisions. Using digital slickline technology has also mitigated risk exposure, as fewer crew hours are spent traveling and handling surface equipment. Examples of intervention work that have been completed with digital slickline services in the KRU include setting retrievable tubing patches, well integrity diagnostics and conventional slickline operations. The operations in the KRU have provided lessons learned and an understanding of the challenges associated with the technology.