Well Intervention

The choice of techniques and equipment to perform the downhole applications determines the mechanical and economic success of a well intervention job.

The Philippine National Oil Company – Energy Development Corporation (PNOC-EDC) has effectively employed several well intervention techniques to address the requirements of sustaining long-term operation of its geothermal production fields. This paper reviews the different intervention techniques and their application to the several field management problems encountered during exploitation. Experiences obtained from these intervention procedures have shown that the chance of success is generally increased with a correct and appropriate engineering approach to any well problem.

Geological and operational uncertainties usually impair the ability of operators to achieve technical and economic goals of a drilling project. Use of real-time data integrated to the earth model has recently reduced the above uncertainties, thus improving project performance. However, the above solution has only addressed part of the overall problem of optimizing the well’s economics, it cannot easily cope with the rapidly increasing amounts of data collected while drilling, and it has not been fully integrated with the control of operations yet. Therefore, we propose a multilayer and multiscale integrated strategy for decision making while drilling and in well intervention. The proposed strategy aims to simultaneously optimize in real time the following four objectives (a) operational drilling performance, (b) initial well completion design, (c) well productivity and (d) value creation. By seeking to optimize an overall integrated objective rather than individual ones, the proposed strategy creates the possibility of achieving a solution that is superior to the aggregate of individually optimized solutions. In this paper we outline the strategy mentioned above and discuss recent applications that support our proposition.

In brownfield developments, prolonging the production life of the wells beyond the 30-year original well design life has been one of the challenges in managing well integrity. This challenge is often compromised by multiple tubing leaks or, in the worst case, by parted tubing caused by metal fatigue, erosion, and corrosion. The issue is often observed in many wells in the S field and usually occurs at a shallow depth between the tubing hanger and subsurface safety valve. The conventional through-tubing repair technique becomes increasingly difficult and ultimately tends to be unsuccessful. Moreover, with the challenge of low oil prices, a simple single-trip system, necessary to reduce costs and increase the success rate, is preferred. Several cost effective approaches to repair production tubing leaks have been available in the market for quite some time. These conventional methods (e.g., stackable slickline straddle, multi-run coiled tubing (CT) conveyed straddle, and tubing patches) come with basic tools, but require difficult manipulation to set and retrieve some of the assemblies, which are permanently installed, that may complicate future well abandonment. For wells with multiple leaks or where the completion tubing has been parted, complete replacement of completion tubing will be the only solution because of the severity of damage. This typically requires a workover rig or snubbing unit at both economically and operationally significant expense. It also typically results in a significant amount time required for well preparation, mobilization, and demobilization of the rig. In addition, the retrieval of this degree of corroded completion is not straightforward because it can come apart piece by piece, which will consume additional time. This paper describes the first customized, through-tubing hanger system installed at the lower master valve (LMV) of its kind. This unique repair method uses a coiled tubing-conveyed swellable packer, a hanging mechanism at the LMV, and through-tubing swellable packer elastomers at both top and bottom of the assembly. A description of the single-trip technology is presented, with a brief description of its engineering development and the installation procedure. The candidate selection process and installation procedure are discussed; information about the economics is provided to demonstrate that this type of repair was economically superior to a rig workover. This paper presents the successful field application of a new well intervention technique to repair multiple shallow leaks in production tubing in S field, an offshore field located in Malaysia. Effective teamwork among various parties through all phases, including engineering design, LMV fabrication, through-tubing hanger customization, swellability laboratory testing, and the execution phase, were key elements to the success of this pioneer project. By demonstrating the operational possibility and a low-cost alternative to an expensive rig workover, this unique technique has created more new opportunities to restore the integrity of shallow leaks and can be run in wells with parted tubing in similar brownfield wells.

Calcite scaling is the leading cause of production loss in Geothermal wells. The most common well intervention technique to combat the issue of scaling is a drilling rig workover. The average cost of well workovers has increased considerably in the last 510 years, resulting in an economical conflict to workover certain wells. In 2013 Contact Energy (CEL, Operator) and Western Energy Services (WES, Service Company) researched, developed, trialled and implemented a wireline intervention technique and methodology to successfully remove and reduce calcite scale in the Ohaaki and Wairakei geothermal fields in New Zealand. This wireline intervention technique, called broaching, is a process developed in the oil and gas industry which uses mechanical tools to remove mainly silica from small diameter production tubing. This process has been transformed to accommodate the geothermal industry by designing tools to combat large volumes of calcite in larger diameter casings. Contact and Western Energy have successfully utilised Broaching to workover 14 geothermal wells regaining over 22MW of production for less than 50% of a single traditional well workover. Perhaps the largest benefit of broaching is that the wells targeted would have been uneconomical or unfeasible to work over using a rig. Broaching has allowed wells that have been dormant for years to contribute to electricity generation. Contact and Western Energy are continuously analysing empirical data from previous broaching jobs to improve tool development, operations and broaden the available window where broaching can be an effective method of geothermal well maintenance. Tool technology, well conditions, wireline experience, and calcite conditions are some of the many outlying variables determining broaching success.

Economic production of oil and gas from tight formations requires complex completions and stimulation treatments such as multistage hydraulic fracturing of horizontal wellbores. In case of tight and competent reservoirs when wells can be completed openhole – this can be done timeand cost-effectively using the assembly comprised of tubular, packers to isolate stages and sliding sleeve valves between them operated with drop ball mechanism. This stimulation technique can be improved further by reducing some of the risks associated with it. First, the length of the treated openhole section for each stage that can reach 1,000 ft. implies no control on the orientation and position of the initiated fracture. Also, rock strength and in-situ stresses can be sometimes so high that it makes the breakdown of the formation impossible without reaching the pressure limits of surface equipment and pumps. Recently, a technique consisting of cutting notches in the wellbore wall was proposed as well intervention steps prior to fracturing operations. Each notch plays the role of a weak-point in the rock which develops high stress concentration at the tip and helps to initiate the fracture at pressures lower than in other parts of the treated section. This allows the initiation of the fracture in the transverse direction and at the exact position of the notch. Due to the initiation of the fracture in the transverse direction and the high stress concentration at the notch tip, the formation breakdown pressure can be significantly lowered. We present new experimental studies of the notching technique along with the latest laboratory results of hydraulic fracturing block tests to demonstrate the benefits of notches. Circular notches were cut using the miniature laboratory analog of a high pressure jetting tool applied in the field. The reported tests repeatedly demonstrate the positive effect of the notch on the orientation of the initiated fracture and the decrease of the breakdown pressure. A reasonable fit between the observed pressure trends and theoretical modeled ones is also obtained and discussed.

As part of the production optimization exercise in J field, an initiative has been taken to enhance the field production target without well intervention. J field is a mature field; the wells are mostly gas lifted, and currently it is in production decline mode. As part of this optimization exercise, a network model with multiple platforms was updated with the surface systems (separator, compressors, pumps, FPSO) and pipelines in place to understand the actual pressure drop across the system. Modelling and calibration of the well and network model was done for the entire field, and the calibrated model was used for the production optimization exercise. A representative model updated with the current operating conditions is the key for the field production and asset management. In this exercise, a multiphase flow simulator for wells and pipelines has been utilized. A total of ∼50 wells (inclusive of idle wells) has been included in the network model. Basically, the exercise started by updating the single-well model using latest well test data. During the calibration at well level, several steps were taken, such as evaluation of historical production, reservoir pressure, and well intervention. This will provide a better idea on the fine-tuning parameters. Upon completion of calibrating well models, the next level was calibration of network model at the platform level by matching against the platform operating conditions (platform production rates, separator/pipeline pressure). The last stage was performing field network model calibration to match the overall field performance. During the platform stage calibration, some parameters such as pipeline ID, horizontal flow correlation, friction factor, and holdup factor were fine-tuned to match the platform level operating conditions. Most of the wells in J field have been calibrated by meeting the success criterion, which is within +/-5% for the production rates. However, there were some challenges in matching several wells due to well test data validity especially wells located on remote platform where there is no dedicated test separator as well as the impact of gas breakthrough, which may interfere to performance of wells. These wells were decided to be retested in the following month. As for the platform level matching, five platforms were matched within +/-10% against the reported production rates. During the evaluation, it was observed there were some uncertainties in the reported water and gas rates (platform level vs. well test data). This is something that can be looked into for a better measurement in the future. By this observation, it was suggested to select Platform 1 with the most reliable test data as well as the platform rate for the optimization process and qualifying for the field trial. Nevertheless, with the representative network model, two scenarios, reducing separator pressure at platform level and gas lift optimization by an optimal gas lift rate allocation, were performed. The model predicts that a separator pressure reduction of 30 psi in Platform 1 has a potential gain of ∼300 BOPD, which is aligned with the field results. Apart from that, there was also a potential savings in gas by utilizing the predicted allocated gas lift injection rate.

The world was feared to hit peak oil early in the 21st century but oil demand continued to grow and most oil and gas companies dedicated a large budget into developing advanced techniques to maximize production from existing maturing fields while minimizing costs in future exploration. Some of these techniques focused on managing the reservoir heterogeneities, enhancing the production lift mechanisms and reducing reservoir damage while drilling. The end goal however was always to increase the ultimate recovery of hydrocarbons from proven reserves. Pakistan an energy deficient country and a net importer of oil and gas is in dire need of self sustainability in oil and gas. Located in southern Pakistan, Qadirpur field once produced upto 600 MMSCFD of gas, currently produces only 250 MMSCFD of gas. The primary reservoir in the field is a water drive reservoir which after extensive pressure depletion has caused water conning and fingering in a large number of wells. Recent attempts to drill new wells have suffered massive lost circulation resulting in severe reservoir invasion damage, and ultimately zero production was observed in a most recently drilled well. As a final resort the operator opted to perform a well intervention in an old and dead well with underbalanced drilling techniques to drill a horizontal leg in the narrow pay zone of the reservoir. The underbalanced drilling campaign was expected to eliminate lost circulation and the ensuing invasion damage to the reservoir formation, characterize the reservoir while drilling and identify sweet spots, and finally increase efficiency of the drilling process and reduce the associated costs. For the pilot well, a multiphase underbalanced drilling fluid was designed to achive extremely low bottom hole pressures, then appropriate directional drilling equipment with electromagnetic measurement while drilling tools were selected to operate with multiphase fluids, and finally a downhole isolation valve was incorporated in the last casing string to allow tripping without the need of ever killing the well. The execution of underbalanced drilling in the pilot well resulted in an unprecedented gas production rate of 14 MMSCFD, identified a sweet spot of hardly 0.5 meters in true vertical depth (TVD) of the pay zone, and increased drilling performance upto 3 times of a conventionally drilled well. The success of the pilot well changed the dynamics of the depleting Qadirpur field as a well intervention on an old and dead well could yield the same production as on a new well while costing half as much. The paper elaborates on the techniques applied and lessons learnt on the pilot well.

The Health, Safety, Environment and Quality (HSEQ) reporting system is used in Well Intervention (WLI) Division of PT Pertamina Hulu Mahakam as one of Oil and Gas Company. WLI operations are considered massive with 21 barges and 890 workers. The barges are spread out onto 6 production sites. They can generate substandard act / situation, Downgraded Situation (DGS), incident, or deviation toward the HSEQ procedure. It shall be monitored and rectified to avoid any escalation and avoid repetition. As part of HSEQ Management System implementation, HSEQ initiative program need to be monitored its progress to achieve Company's Objective (lagging indicator). The initiatives consist of audit/ inspection, emergency drill, meeting, and visit. The need of database recording system is unavoidable to manage the operations accordingly. It triggers the development of reliable and user friendly application to learn from the event and initiative reporting system. The application is officially launched in mid of 2017 after 6 months of development. 2nd Chance is developed internally by considering Company Rule, operational user expectation and experience operating in Mahakam field. The reporting system consists of HSEQ Anomaly, Downgraded Situation (DGS), Incident and Initiative. The tool is accessible everywhere with Company's network access (intranet), capable to accommodate all essential information with smart interactive features i.e. user friendly and able to avoid unnecessary mistakes. It is equipped with automatic graphical dashboard to analyze the trends. Company's Objective is to obtain zero Loss Time Incident (LTI) operation could be achieved by the management of learning from the event as continual improvement process. WLI Division achieves 540 days without LTI with 5.33 million man-hours in 2017 - 2019.

Electrical lines, also known as wirelines, are commonly used for well intervention techniques to increase flow of oil and gas wells that can be executed during a low service time. Previous studies show the importance of this electrical conductor for power delivery as well as communication purposes. Nevertheless, a validated model and its parameters of this channel are still missing. This papers outlines a geometrical approach to estimate the electrical dynamic behavior for wireline types used in the field with results supported by four different types of validation. The proposed method proves to capture the wireline dynamic behavior characteristics and is particular accurate in modeling the capacitive element within 5 %.