Successful Remediation of Sustained Casing Pressures in Gas Cap Injector Wells with the Use of Flexible and Self Healing System

Several injection wells in Prudhoe Bay, Alaska exhibit sustained casing pressure (SCP) between the production tubing and the inner casing. The diagnostics on these wells have shown communication due to issues with casing leaks. Conventional cement systems have historically been used in coiled-tubing-delivered squeeze jobs to repair the leaks. However, even when these squeeze jobs are executed successfully, there is no guarantee in the short or long term that the annular communication is repaired. Many of these injector wells develop SCP in the range of 300-400 psi post-repair. It has been observed that the SCP development can reoccur immediately after annulus communication repair, or months to years after an injector well is put back on injection. Once SCP is developed the well cannot be operated further. A new generation of cement system was used to overcome the remedial challenge presented in these injector wells. This document provides the successful application of a specialized adaptive cement system conveyed to the problematic zone with the advantage of using coiled tubing equipment for optimum delivery of the remedial treatment.

Novel Application of Epoxy Resin to Eliminate Sustained Casing Pressure Without Costly Downhole Well Intervention - Case History from East Kalimantan, Indonesia

An operator recorded 1100 psi of sustained casing pressure between a 9-5/8" casing and a 3.5" production tubing annulus seven days after the cementing operation was completed for the 3.5" production tubing. A production logging run was performed, and results indicated gas was flowing from a zone 86 feet below the 9-5/8" casing shoe. As per the operator's standard, such a situation suggests subsequent well completion operations cannot be processed and must be remediated. The most common solution for such situations is to perforate and squeeze to ensure zonal isolation in the zone from which the gas is flowing. Due to the slim tubing size this operation can be difficult, and there exists a high risk of leaving set cement inside the 3.5" tubing. Furthermore, drilling would require extensive time with a coil tubing unit and in the worst case could lead to the loss of the well. To provide a dependable barrier for long term well integrity, a novel approach consisting of epoxy resin was discussed. A highly ductile, solids-free resin was designed and tailored to seal off communication from the gas source to surface. The void space in the annulus was estimated to be less than 5 bbl. An equipment package was prepared to mix and pump the resin into the annulus. Resin was pumped through the wellhead casing valve using a hesitation squeeze technique with the maximum surface pressure limited to 3000 psi. Once all resin was pumped, the casing valve was closed to allow enough time for the resin to build compressive strength. The job was planned to be performed in multiple stages consisting of smaller volumes. The job was completed in two stages, and the annular pressure was reduced. On the first job, 1 bbl of resin was mixed and injected into the annulus. The pressure build up was decreased from 550 psi per day to 27 psi per day. To lower the annular pressure further, a second resin job was performed using 0.35 bbl resin volume, which further reduced the annular pressure build up to 25 psi within 3 days. No further stages were performed as this was considered a safe working pressure for the well owner. After 2 months no annular pressure was observed. The application of this tailored resin helped to improve the wells integrity under these circumstances in this high-pressure gas well. Epoxy resin with its solid-free nature and deep penetration capabilities helped to seal off a very tight flow path. This application of pumping resin through the wellhead to overcome annular gas pressure can be an option when the flow path is strictly limited, or downhole well intervention is very difficult and risky.

Advanced Remedial Hydraulic Isolation by Perforate and Wash Technique

Well Cementing can be divided into two phases – primary and remedial cementing. Primary cementing may have 3 functions: casing support, zonal isolation and casing protection against corrosion. First two functions are commonly recognized while the third one might be a point of discussion, as the full casing coverage with 100% clean cement is not something common in most of the fields. In fact, poorly cemented areas of the casing may become negatively charged and create a zones of accelerated corrosion rate. This paper is about main role of cementing - zonal isolation. The process of primary cementing assumes that cement slurry is being pumped into the casing and displaced outside. After wait on cement time (WOC) it becomes hard, develops compressive strength and creates impermeable seal that ensures hydraulic isolation. Old and well-known technique, it still remains one of the most challenging rig operations. It is unlikely to find a service company that would guarantee 100% cement displacement behind the casing all the way from top to bottom. Main challenges in this region are quiet common for many other fields – displacement in deviated sections, losses before and during cementing, exposure to pressure during cement settling. In case the main target is not achieved (no hydraulic isolation behind the casing) – we may observe behind casing communications resulting in sustainable pressures in casing-casing annuluses. In this situation the remedial cementing takes place. It's function is to restore isolation so the cement can work as a barrier that seals off the pressure source. Despite of the good number of sealants available on the market (time, pressure, temperature activated) that can be injected from surface to cure this casing-casing pressure, Company prefers not to do so unless there is a proven injectivity capability that would allow for the sealant to reach deep enough, to protect aquifers in case of outer casing corrosion. Otherwise that would be just a ‘masking" the pressure at surface. Therefore in general Company prefers rig intervention to cure the pressure across the cap rock in between the aquifers and the reservoir. Those aquifers are illustrated on the Figure 1 below: More details on Company casing design, cement evaluation issues, sustained casing pressure phenomena and challenges have been mentioned previously [Yugay, 2019].

Optimising Depth Selection on Section Milling Operation to Secure Sustained Casing Pressure During Plug and Abandonment Operation

D-01 was an exploration well requiring a Plug-and-Abandonment (P&A) procedure with sustained casing pressure up to 2,000 psi on the B annulus. The presence of Sustained Casing Pressure (SCP) is one of the major technical challenges to decommission and abandon the well safely. Several attempts to secure the well using the perforation-and-squeeze method were performed – but failed. It was decided to perform section milling operations to create a viable rock-to-rock barrier. In this operation, the key factor in determining success, is selecting the correct depth to mill safely and secure the annular pressure source. A comprehensive approach was taken to determine the optimum depth for the section milling by evaluating existing open-hole and cased-hole data. Additionally, triple-detector Pulsed Neutron Log (PNL) was also performed prior to the section milling operation. The triple-detector PNL tool offered not only behind casing porosity (TPHI) and sigma (SIGM) measurement, but also a relatively new measurement in the oil and gas industry called Fast Neutron Cross Section (FNXS), which were expected to provide more accurate gas detection and gauge the condition near the borehole. By combining all the logs and reservoir data, the milling interval was selected and the section milling and subsequent cement plug operations were performed. Evaluation of existing open-hole and cased-hole logs provided geological and petrophysical insights which were useful in determining the hydrocarbon source charging the B-annulus. Further analysis on PNL data provided indication of possible gas pockets in the B-annulus. This information was used to distinguish between shallower formation sources or gas pockets that were not yet bled off. The operation on D-01 successfully resolved the B-annulus issue and the well was properly abandoned per regulatory requirements. Considering the complexity and high cost of section milling operations, a thorough review of data and pre-job logging increases the probability of selecting the optimum intervals needed to successfully complete P&A operations on SCP wellbores.

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.

Fluid Migration Characterization of Full-scale Annulus Cement Sections Using Pressure-Pulse-Decay Measurements

Fluid migration behind casings is a well integrity problem that can result in sustained casing pressure, undetected leaks to the environment and potentially very challenging remediation attempts. Understanding the geometric dimensions and extent of annular migration paths is important for diagnosing and effectively treating fluid migration and sustained casing pressure problems in wells. We report measurements of permeability and micro-annuli in two full-scale cemented annulus test sections using a combination of transient pressure-pulse-decay and steady state seepage measurements. One of these sections is a cemented 9 5/8-in and 13 3/8-in casing section from a 30 years old Norwegian North Sea production well. For both sections we find equivalent micro-annulus sizes that are within the range of effective wellbore permeabilities based on sustained casing pressure records and previous vertical interference tests in wells. The test sections display measurable axial permeability variations with the bottom part of these vertical sections having the lower permeability. For the retrieved casing section the change corresponds to the transition through the top of cement which is nearly in the middle of the test section. Increasing internal casing pressure is found to slightly reduce the equivalent micro-annulus size, indicative of fracture-like response of the migration paths. A perceived benefit of the transient test procedure discussed herein is a significantly faster permeability characterization especially within low-permeable sections where it is otherwise difficult to establish steady state flow conditions.

Well Integrity Diagnostics Using Acoustic Event Classification on Distributed Acoustic Sensing Data

Injection wells experience extremes of pressure and temperature as well as expansion and contraction during their normal operating cycles. This can cause numerous well integrity issues related to corrosion, leakage, degradation of barrier elements, operational practices that all put the health of the well at risk and require appropriate management. This paper will describe a case of a North Sea injection well that over time had developed sustained casing pressure (SCP) in the B-annulus. As a critical well in the development it was necessary to understand the origin and nature of the SCP as this would set further operational plans for the well helping to decide whether the well could continue to be operated safely, would require an intervention, or potentially will be abandoned. A leak investigation was needed to try to determine the source of the pressure, the type of fluid causing the pressure, the fluid path, and whether there was an injection out-of-zone as a result. To address all of the set objectives Distributed Fibre Optic (DFO) system was selected as a technology of choice. DFO provides an advantage over traditional leak detection methods through the ability to simultaneously monitor entire length of the well recording both acoustic and temperature profiles. Distributed Acoustic Sensing (DAS) was used to record acoustic signature of the well helping to determine the leak origin and likely pathway, while Distributed Temperature Sensing (DTS) was used to record well outflow profile and advise on possibility of out-of-zone injection. Use of pattern recognition techniques allowed to extract leak signature from background noise and other acoustic signals helping to pinpoint leak location. As a result of the application of DFO technology coupled with appropriate processing techniques way ahead for the well was identified providing an operator with a confident answer and saving on further intervention costs.

Mechanically Enhanced Cementing: Mitigation Against Sustained Casing Pressure in Highly Stressed Downhole Environment, Offshore Niger Delta

A major Exploration and Production (E & P) company was posed with a challenge of sustained casing pressure in over 85% of the wells drilled in one of the fields in the Offshore Niger Delta. Sustained casing pressure occurs when the annular seal is damaged and a path is created for the formation pressure to reach the surface, and the pressure in the annulus rebuilds after being bled down. When cementing in such an environment, operators have the following objectives: Placing a cement sheath with increased capability to survive future downhole stress events.Achieving effective mud removal.Gaining the benefits of a react and respond sheath design.Providing a long productive life for the wellbore. To develop a cement system that would achieve and maintain isolation throughout the life of the well, an advanced cement technology was required. This advanced cement technology involved Finite Element Analysis (FEA) to model the effects of stresses from well operations on the cement sheath. This analysis takes into consideration well configuration, formation properties, casing properties, cement properties and operational loads and predicts the remaining capacities of the cement sheath. The remaining capacity is used to measure how much a cement sheath is stressed. After simulating the effect of downhole stresses on a cement sheath, a mechanically enhanced cement slurry was designed to meet the recommendations of the model and provide a cement sheath with improved remaining capacity. This paper presents the successful mechanically enhanced slurry design, job design, planning and execution on the production section of the well after a Finite Element Analysis was conducted. Post job conditions such as good cement bonds across cemented areas, well production without inter-zonal communication and no annular pressure build up in over 8 years have proven the success of the design and the procedure implemented in these challenging well bore environments. The success of this well has been applied to two additional wells.

Study of Ultrasonic Logs and Seepage Potential on Sandwich Sections Retrieved from a North Sea Production Well

Summary Important functions of well cement are to provide zonal isolation behind casing strings and to mechanically support and protect the casing. Experience suggests that many wells develop integrity problems related to fluid migration or loss of zonal isolation, which often manifest themselves in sustained casing pressure (SCP) or surface casing vent flows. Because the characteristic sizes of realistic migration paths are typically only on the order of tens of micrometers, detecting, diagnosing, and eventually treating migration paths remain challenging problems for the industry. As part of the recent abandonment operation of an offshore production well, sandwich joints comprising production casing, annulus cement, and intermediate casing were cut and retrieved to surface. Two of these joints were subjected to an extensive test campaign, including surface relogging, chemical analyses, and seepage testing, to better understand the ultrasonic-log response and its potential connection to rates of fluid migration. One of the joints contained an apparently well-defined top of cement (TOC) with settled barite on top. Although the settled material initially provided a complete seal against gas flow, the sealing capability was irreversibly lost as part of subsequent testing. The two joints have effective microannuli sizes in the range of tens of micrometers, in agreement with previous reports on SCP buildup in wells. On a local scale, however, we observed significant variations in cement quality from both the log results and the seepage testing. Further, we found qualitatively very good correlations between seepage-test results and the log results for the bond between cement and casings. The best bonded cement was found directly above a production casing collar, where a short segment of well-bonded cement prevented measurable steady-state seepage of nitrogen. Additional tests involving internal pressurization of the production casing suggested that certain annular-seepage characteristics are well-described by an effective microannulus at the cement/casing interfaces. We consider the two sandwich joints to be highly representative and relevant for similar mature wells that are to be abandoned.

Downhole Annular Barrier Solution for Sustained Casing Pressure - Trinidad Case Study

Objectives/Scope Downhole Annular Barrier (DAB) systems employed in intervention can correct integrity and conformance control issues during well lifecycle, extending the productive term in a safe and costeffective manner. These emergent wireline technologies come with unique challenges for logistics, quality control, and engineering, but can also provide solutions to difficult problems, with high value to spend ratio, in the non-rig intervention sector. The paper will review one such successful intervention, completed offshore Trinidad W.I., in a gas well presenting long term Sustained Casing Pressure (SCP). The desired end state of the well was A-Annulus at 0 psi SCP, which would return the well to a safe state and permit a planned infrastructure project to move ahead. Methods, Procedures, Process Operational objective was isolation of the casing annulus pressure from the source by injecting epoxy into the annular space at depth, forming a 360-degree pressure barrier. The project can be broken down into three main sections. The paper and presentation will address each section with its specific challenges, learnings, and outcomes: Onshore Epoxy and Tool Preparation Each Downhole Annular Barrier job employs a custom recipe epoxy suited to the planned logistics timing and expected bottomhole conditions. Quality control of the epoxy recipe and mixing process as well as temperature control of the batch after mixing is key to the sealing properties of the final epoxy plug. • An Epoxy Lab and Mixing Station was dismantled, air freighted, and reconstituted in Trinidad near to the field operations port. Special insulated offshore CCU were built to transport and contain filled epoxy canisters while maintaining low temperature requirements (near to 0 deg C for up to 30 days). • Build and System Integration Testing (SIT) of the downhole system (anchoring, stroking, hydraulic testing, perforation, and injection) with the electric line system (conveyance, telemetry, power). Offshore Job Execution The DAB system employed is designed to complete multiple operations in a single trip into the well, including perforating and high-pressure epoxy injection, with precise position control and monitoring. This is made possible with the multi-function modular tool. The operation was dynamic by design and contingencies were implemented based on the well response. Multiple epoxy annular plugs were placed into the A Annulus at depth, with high pressure injection. Results, Observations, Conclusions Well Response and Assessment Utilizing advanced annular surface monitoring technology and PvT analysis, precise assessment of the annulus pressure build was recorded throughout the operation. Once the project criteria were met, the operation was successfully concluded.