Reservoir Engineering and Geomechanical Aspects of Well Plugging and Abandonment

With the maturation of many oilfields, further well abandonments will occur in the years to come. There are issues about improper well abandonment that can have far-reaching effects for responsible companies or entities. At this time in the US, where most of the operation is operated by non-government entities, sometimes the sovereign state may end up covering the cost of well abandonment when the operator is not financially capable in managing such costs. That will be a burden to the public taxpayers. In this paper, we review an important aspect of the well abandonment practices and at present, based on a reservoir modeling approach, more clearance on the potential formation of free gas that can be a cause of concern. We also discuss the integrity issues of the sealing process. We point out how the development of cracks caused by many factors, including geomechanical effects or slow deterioration of the cement seal, in the long run, may result in generating escape paths for the evolved hydrocarbon gases.

A Novel Method to Determine the Drilling Fluid Density for Gypsum-Salt Layer

The reservoir underneath the salt bed usually has high formation pressure and large production rate. However, downhole complexities such as wellbore shrinkage, stuck pipe, casing deformation and brine crystallization prone to occur in the drilling and completion of the salt bed. The drilling safety is affected and may lead to the failure of drilling to the target reservoir. The drilling fluid density is the key factor to maintain the salt bed’s wellbore stability. The in-situ stress of the composite salt bed (gypsum-salt -gypsum-salt-gypsum) is usually uneven distributed. Creep deformation and wellbore shrinkage affect each other within layers. The wellbore stability is difficult to maintain. Limited theorical reference existed for drilling fluid density selection to mitigate the borehole shrinkage in the composite gypsum-salt layers. This paper established a composite gypsum-salt model based on the rock mechanism and experiments, and a safe-drilling density selection layout is formed to solve the borehole shrinkage problem. This study provides fundamental basis for drilling fluid density selection for gypsum-salt layers. The experiment results show that, with the same drilling fluid density, the borehole shrinkage rate of the minimum horizontal in-situ stress azimuth is higher than that of the maximum horizontal in-situ stress azimuth. However, the borehole shrinkage rate of the gypsum layer is higher than salt layer. The hydration expansion of the gypsum is the dominant reason for the shrinkage of the composite salt-gypsum layer. In order to mitigate the borehole diameter reduction, the drilling fluid density is determined that can lower the creep rate less than 0.001, as a result, the borehole shrinkage of salt-gypsum layer is slowed. At the same time, it is necessary to improve the salinity, filter loss and plugging ability of the drilling fluid to inhibit the creep of the soft shale formation. The research results provide technical support for the safe drilling of composite salt-gypsum layers. This achievement has been applied to 135 wells in the Amu Darya, which completely solved the of wellbore shrinkage problem caused by salt rock creep. Complexities such as stuck string and well abandonment due to high-pressure brine crystallization are eliminated. The drilling cycle is shortened by 21% and the drilling costs is reduced by 15%.

Deep Penetration Resin Systems Overcome Annular Gas Migration: Case History

Well Integrity is a critical compliance requirement during oil and gas operations. Abandonment procedures must ensure that all hydrocarbon sources are properly isolated and effective barriers are placed. This paper describes the use of resin systems to isolate annular gas migration identified during the Obiwan – 1 well abandonment in Colombia. The main challenge was to select and design fluid systems capable to fill tight spaces and isolate the annular channel. Resin systems are high-strength, elastic polymers which act as dependable barriers to isolate fluid flow. They can be designed as a solid-free, pure liquid or may contain solids (cement with a formulated percent of resin). Solid-free formulations are ideal for remedial operations, such as isolating annular gas. Acoustic logging enabled identification of the influx zones. Annular isolation was achieved by executing two cementing remedial operations using the bradenhead squeeze technique. A tailored resin system was selected to deliver the proper barrier addressing the influx zones after injectivity tests were performed in each interval. For the first intervention a solids-free resin system was used, and for the second one a resin-cement composite system was applied. During cementing remedial operations, it was determined that the resin systems were able to achieve deep penetration into the channels more readily and form a seal. The correct system was selected for each case, and during execution, the required volume was injected to intersect and properly isolate the annular gas channel. As a result, the tailored resin systems isolated the gas channel eliminating annular pressure and gas migration to surface. In addition, a post remedial operation acoustic log indicated that the influx zones were successfully isolated. Well abandonment was accomplished according to country regulatory requirements and delivered dependable barriers both annular and interior pipe sections. Use of resin to repair channels of this type exhibited a higher success rate and improved reliability in comparison to conventional particulate-laden fluids, which helps to decrease costs for additional remedial treatments.

Enabling Safe and Efficient Well Plug & Abandonments Through Use of Rigless Technologies

The growing number of upcoming well abandonments has become an important driver to seek efficiencies in optimizing abandonment costs while establishing long term well integrity and complying with local regulatory requirements. With an increasing global inventory of Plug and Abandonment (P&A) candidates, Exxonmobil has been driven to look for the most reliable, safe, and cost-efficient P&A technologies. ExxonMobil's P&A guidelines are consistent with and often more stringent than the local regulatory requirements but are also achievable, at least in part, with rigless technologies, leading to a more cost-efficient approach while ensuring well integrity. The objective of this paper is to demonstrate the success of rigless abandonments and their benefits compared to rig-based solutions. When developing a well abandonment plan, it is essential to consider a number of factors. These include local regulations, identification of zones to be isolated and suitable caprocks, and recognition of constraints including well history, conditions and uncertainties. Teams should begin with low cost operations without a rig if possible, estimate costs and effectiveness to achieve the barrier requirements, and evaluate batch operation opportunities for multi-well programs. ExxonMobil case studies are shown to help describe in detail how to make decisions about applicability of rigless abandonment options and how to properly execute such abandonments to achieve compliance with the barrier requirements. It has been demonstrated that significant cost savings can be achieved by staging the abandonment program in a way that lower cost technologies are utilized during the early stages of well abandonment, starting with wireline where possible, followed by coiled tubing and finally by a pulling unit, as appropriate. P&A execution could be achieved without a rig in a majority of cases, including most offshore wells, with the need to use a rig only in special circumstances or phases of execution. It is important to note that the barrier placement and safety of rigless P&A execution will not be compromised, as compared to the rig-based P&As. Additional cost savings could be achieved by further optimizing P&A design at the well design stage, ensuring that there are no built-in limiters that would prevent rigless P&A execution at the end of well life. Several case studies from ExxonMobil's global offshore experience demonstrate the feasibility and effectiveness of rigless P&A operations, with significant cost savings compared to rig-based P&As. It has been evident that rigless P&A choice is applicable to the variety of ExxonMobil's P&A projects of different complexities, with the same or superior quality of abandonment and safety record.

Offline Well Abandonment SIMOPs: An 81 Well Phase I & II Case Study Enabling ABEX Reduction in South East Asia

In the decommissioning phase of oilfield facility lifecycles, focus pivots from positive net present value to executing the care and preservation, then decommissioning in the safest and most environmentally sensitive manor, and at the lowest total cost of ownership. Asset Retirement Obligation (ARO) is a long-term liability carried on the balance sheet, as a provision for the cost to return a wellsite to pre-exploration condition. The reduction of abandonment and decommissioning expenditure (ABEX) in executing compliant operations is a key business performance factor, and critical in executing higher volumes of wells earlier than planned. In doing so maximizing value to company shareholders, residents, industries and government level stakeholders. In the case study, an offline pre-abandonment and Phase I primary reservoir isolation project is presented, which seeks to maximize net project efficiency via offline wellbore intervention, executing the primary reservoir isolation of the wellbore via rigless techniques. This approach contributed to ABEX reductions by up to 40% per well vs the planned approval for expenditure (AFE) provisions taken for the operations. The project execution structure utilized offline intervention and Phase I primary reservoir isolation of 81 wellbores, across 5 wellhead platforms and 47 days continuous operations. Operations were part of a simultaneous operation (SIMOPS) project, as an offline work front located on the wellhead platform (WHP) weather deck. A second work front for Phase II and Phase III well abandonment operations, is executed concurrently, from the jack-up rig cantilever above the WHP. Live well operations are conducted concurrently by both work fronts, through the Christmas Tree (XT) and pressure control equipment in Phase I, and through the drilling riser and blowout preventor for Phase II and Phase III, to maximize productivity when the rig is on location. The scope of operations included wellhead qualification, wellbore access and preparation, well kill, injectivity testing, various wellbore preparation and cement placement techniques, pressure testing and lubrication of the wellbore. The operator's system engineering, design of operations and planning agility are key to its success. Acute focus was given to the batching of operations and delivery of these in a phased approach to increase productivity and maintain high service delivery through repetition of tasks. The project successfully executed Incident Free Operations (IFO) with 100% productive time and facilitated combined project performance, which delivered wells up to 44% ahead of the planned AFE. To enable this, over 4.19 million feet of slickline was run, conveying 428 bottom hole assemblies (BHAs), preparing the wellbores to isolate 804 primary reservoirs, and 2 intermediate reservoirs.

Reducing ABEX Uncertainties through Hybrid LSTK Contracting: A Factory EPSm Pilot Case Study in South East Asia

Well abandonment and the associated abandonment expenditure (ABEX) are necessary stages in the post cessation of production (Post COP) phase of the asset lifecycles. There are significant risk factors present, which vary in the frequency and severity based on a multitude of factors pertaining to environment, age, well construction techniques and stratigraphy, to name a few. In the case of well isolation and abandonment operations there are opportunities to innovate through factory project execution techniques and commercial approaches, which are enhanced where standardization and commonality of well architecture is present. These techniques focus on reducing risk factors and creating value where conventional thought suggests there is marginal cashflow benefit, in asset retirement obligation expenditure. Through a reduction in the total cost of ownership (TCO), project financial performance below the estimated provisions, can unlock cashflow from relief adjustments on long term liabilities. The Engineering, Procurement, Services management (EPSm) lump sum partial turnkey contracting approach was developed to assist operators in unlocking cashflow in ABEX provisions, through risk reduction via front end well engineering and integration of service provision, allied to fixed price lump sum contracting to control project cost creep due to unforeseen events. A pilot project was undertaken in South East Asia, delivering 64 permanently abandoned wellbores in 38 consecutive days, representing over 8,300-man hours and over 3,500 operating hours. The EPSm contracting approach delivered lump sum partial turnkey well abandonment services in a high-volume factory well abandonment retirement environment. Operations were executed through a dedicated jack-up drilling rig trimmed to an asset retirement specification to reduce OPEX and increase efficiency. The operational project framework implemented pre-abandonment offline operations prior to rig arrival, then simultaneous operations (SIMOPs) concerning 2 primary worksites: the wellhead platform weather deck and the jack-up rig cantilever. Standalone concurrent Phase I slickline operations comprising of two units, were performed offline on the wellhead platform with pressure control equipment to execute primary reservoir isolation operations. Phase II & III operations were executed above, on the jack-up rig cantilever through the drilling riser and pressure control equipment, executing the overburden and surface isolation operations, minimizing online operating time of the jack-up rig. Key Learnings from the pilot project are presented, along with pilot project key performance indicators. The project learning curve, and human performance factors provide insights to areas where there are synergies and opportunities to further reduce risk and the total cost of ownership through an Engineering, Procurement, Services management (EPSm) contracting approach.

Case Study and Lessons Learnt for the 1St Fully Integrated Hwu Well Abandonment at Field a Offshore Malaysia

Uzma was awarded with 1st integrated well abandonment under Provision of Well Abandonment Integrated Services (WAISE) in 2018. Total of 22 wells were plug & abandonment with average 10 to 20 days per well were spent to complete the work. The scope of works is inclusive providing Project Management Team, Hydraulic Workover Unit, Accommodation Work Boat, Supply Vessels, and P&A services. This paper will highlight the practical experiences and capture the lessons learned obtained executing 1st integrated well abandonment campaign in Field A Offshore Malaysia. This paper presents the overall project lesson learnt for 1st integrated well abandonment embarked from early stage of project planning, preparation, acceptance, technical, operation & project close out. The lesson learnt will be beneficial for all Operator & Contractor Company involving with integrated well abandonment. This paper also presents capability of hydraulic workover unit and recommendation for future of low-cost well's plug and abandonment. Plug and abandonment operations with conventional hydraulic workover units have an enormous impact on low-cost plug and abandonment campaign in Malaysia compared with conventional drilling rigs. In essence, the lessons learned and insights gained throughout abandonment campaigns will keep accumulating with time to feed into the knowledge and experience vault. With proper project lesson learnt, many success cases and best practices can be emulated both from technical and commercial point of view. This lesson learnt will be beneficial for all Operator & Contractor Company involving with integrated well abandonment.

Indonesia Well Abandonment Standard Gap Analysis; A Review and Suggestion

The old oil and gas wells of approximately 70% are found to have no economic value in Indonesia, leading to being abandoned during the end of their lifecycle, as ruled by the government. This is part of decommissioning an entire field with an environmental preservation program, known as an Abandonment and Site Restoration (ASR). The program involves the evaluation of international permanent abandonment standards, as references for the designs, comparisons, and assessments of Indonesia’s policies. It also provides contrast gap analysis and suggestions in ensuring a proper permanent plug and abandonment approach, to avoid any future leaks or re-abandonment operations. Therefore, this study aims to determine and evaluate the gap analysis between Indonesia and International Well Abandonment Standards, as well as OGUK and NORSOK D-010. The results showed that abandonment activities had improvement opportunities philosophy, and practice, used for plugging/isolations, control lines, as well as reservoir and annular barriers. In addition, literature studies were performed to understand the abandonment philosophy for all reviewed standards, to provide proper suggestions or improvements.

Development and Implementation of the Method of Cementing Production Casing 178 mm with Pressure on the Cement Slurry on the East Part of the Orenburg Oil and Gas Condensate Field

Well construction in the Volga-Ural Region faces different sorts of complications, the most common ones being the loss of drilling fluids and rockslides. Such complications may cause considerable financial losses due to non-productive time (NPT) and longer well construction periods. Moreover, there are complications, which might occur both during well construction and during its exploitation. The commonest complications are sustained casing pressure (SCP) and annular flow. The complications, which occur when operating a well, also have a negative effect on the economic efficiency of well operation and call for additional actions, for example, repair and insulation works, which require well shutdown and killing, though a desired outcome still cannot be guaranteed; moreover, it is possible that several different operations may have to be carried out. In addition, the occurrence of SCP during well life is one of the most crucial problems that may cause well abandonment due to high risks posed by its operation. It is known that the main reasons for SCP are as follows: Channels in cement stone Casing leaks Leaks in wellhead connections To resolve the problem of cement stone channeling, several measures were taken, such as revising cement slurry designs, cutting time for setting strings on slips, applying two-stage cementing, etc. These measures were not successful, besides, they caused additional expenses for extra equipment (for example, a cementer). In order to reduce the risk of cement stone channeling, a cementing method is required that will allow to apply excess pressure on cement slurry during the period of transition and early strength development. To achieve this goal, a well-known method of controlled pressure cementing may be applied. Its main drawback, however, is that it requires much extra equipment, thus increasing operation expenses. In addition, the abovementioned method allows affecting the cement stone only during the operation process and / or during the waiting on cement (WOC) time. Upon receiving the results of the implemented measures and considering the existing technologies and evaluating the economic efficiency, the need was flagged for developing a combined cementing method. The goal of this method is to modify the production string cementing method with a view to applying excess pressure on cement stone during strength development and throughout the well lifecycle. The introduction of this lining method does not lead to an increase in well construction costs and considerably reduces the risks of losing a well from the production well stock.

Flawless Cutting of Tubing and Control Lines by Mechanical Pipe Cutter in Challenging Well Condition Provides an Environmental Friendly Alternative: A Case Study from Brunei

The Electro-Mechanical Pipe Cutter (MPC) is a non-ballistic & non-chemical wireline deployed alternative cutter tool for parting downhole tubular in the process of well abandonment, pipe recovery and retrieving of packer elements. This case study showcases its application in two wells with different challenges in cutting 4.5" tubing viz., (i) with multiple control lines to facilitate fishing operations and (ii) under compression in a highly deviated trajectory. In Well A, Brunei offshore, the position of the tubing and orientation of the control lines were challenging for ballistic option, along with the possibility of scarring the 9-7/8" casing during the cutting operation. Thus, 3-1/8" OD MPC was used for this job to cut near the coupling, ensuring optimum stand off from casing wall aiming to achieve cutting the control lines in tension. Dual cut were designed to allow the room for a safe cut zone. The primary cut was performed near middle of the joint at ∼1985m, with the tubing in tension. The cut was initiated at a very slow feed (0.2 mm/min) and motor rates (4000rpm), which was gradually increased once the cutting was stable. After the accomplishment of the tubing cut, the parameters were again reduced to carefully cutting through control line. The tubing was successfully retrieved with smooth cut without any over pull indicating it to be completely free. The flawless cutting operation was performed in less than one hour with outmost efficiency. In another highly inclined Well B, Brunei offshore, MPC was chosen over ballistic because it was needed to be conveyed by tractor and ballistic shock has potential to damage it during the operation. Also the advantage of MPC to perform multiple cuts in one run, made it a preferred choice. In this well, multiple cuts were performed to weaken the joint connection of the tubing to allow the rig to pull it free. It was to overcome the adversity posed by high inclination and the pipe under compression. Three cuts were performed at ∼2996 m, each 20 cm apart with an OD of nearly 4.609". After completion of the job, the circulation was performed with surface return, indicating successful execution and the tubing was retrieved on surface showing a clean cut. This case study shows the appropriate planning and execution of the mechanical pipe cutter can provide an efficient, environment friendly and safe alternative to cut tubing and control line in the challenging condition especially when an explosive and chemical cutter options are not considered suitable.