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].

Plug and Abandonment for Gas Wells: A Case Study from Baghjan Oilfield, India

The economic end of the life-cycle of a well is dynamic and it varies with the oil & gas market conditions and advances in extraction technologies. If production declines or the need for a workover arises, plugging and abandonment operations are followed. In case the wellsite has encountered accidental releases, systematic abandonment and remediation becomes even more crucial to avoid further environmental damage and capital investment. This paper analyzes the Baghjan oilfield blowout of the Assam-Arakan basin and provides abandonment practices for gas wells. The mobile workover rig was stationed at the Baghjan Well-5 with the aim to plug the lower producing zone at 3871 m and complete the well in the upper Lakadong+Therria sand at a depth of 3739 m. Baghjan Gas Well No.5 blew during the temporary abandonment which was planned to mitigate the leakage in the wellhead. Improper depth for the placement of cement plug, failure to check the plug integrity, and shortcomings in the regular inspection of annular casing pressure led to the well control situation at the Baghjan gas well. While pulling out the tubing conveyed perforation gun after perforating the Lakadong+Therria I+II sand, Shut-In Tubing Pressure of 4400 psi and 3900 psi Shut-In Casing Pressure was observed which indicated a leak in the Tubing Seal Assembly. The well was killed with a 9.76 lbm/gal sodium formate brine and in the middle of pulling the tubing, leakage in the W.F. Spool was identified which changed the priority of the operations. Therefore, a temporary abandonment operation was planned to mitigate the leakage problem in the primary and secondary seals, during which the well started flowing gas profusely after nipple-down of the blowout preventer. The shortcomings of the abandonment process can be conquered by the selection of an appropriate isolation material such as resin-based sealants or bismuth and thermite, which shall act as a primary barrier and provide enhanced zonal isolation. The isolation material should mitigate micro-fractures, minimize treatment volume and fluid loss, provide ample pumping time, and not degrade in the presence of wellbore fluids. The study discusses resin-based sealants, cement slurry designs, advances in conventional, unconventional, and rigless abandonment techniques, and suggests the most efficient method for the temporary and permanent abandonment operations to avoid further such incidents in the oil and gas industry.

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.

Comparison and adaptability evaluation of formation pressure calculation methods and computer simulation in Jingbian gas field

In the process of oilfield development, formation pressure is an essential parameter for evaluating oilfield development effect, calculating dynamic geological reserves, conducting daily dynamic analysis of oil and water Wells and predicting oilfield performance. The pressure recovery time of conventional gas well after shut-in is very long, and it is difficult to effectively carry out targeted implementation due to the influence of gas field external supply task. In this paper, based on the actual data of Jingbian gas field, through the comparison of several calculation methods of formation pressure, the best method to calculate formation pressure is comprehensively screened out. The results show that: ①For a single method, the accuracy of the method from high to low is the well head casing pressure conversion method, the pressure drop curve method, the binomial productivity equation method, and the quasi-steady state mathematical model method.②The absolute error of multi-method comprehensive calculation method is 0.9MPa, which is far less than the average absolute error directly calculated by one method. The multi-method comprehensive calculation method is reliable when applied to the formation pressure evaluation of typical gas Wells in Jingbian gas field, which lacks data.

Successful Appraisal Cum Development of Shallow and Poorer Quality Gas Reservoir in Mature Field at Minimal Cost

The Cement Packer approach has been successfully implemented in ExxonMobil Exploration & Production Malaysia Inc. (EMEPMI) to further develop minor gas reservoirs. The reservoir of interest is of relatively poor quality and has not been tested, thus making conventional development potentially not cost effective. Several viable approaches were identified and assessed to appraise and develop the reservoir. The cement packer method, which requires relatively minimal investment was then selected as being the most suitable in pursuing these behind casing opportunities. Group 1 sands in Field A are the shallowest hydrocarbon reservoirs which are relatively thin and have low porosity and permeability. The existing completions are currently producing from deeper reservoirs, with the top packer located below the Group 1 sands. Developing the opportunities behind casing in these sands using the conventional pull tubing workover approach may be cost prohibitive. The cement packer approach, where the tubing was punched to create tubing-casing communication and cement was subsequently pumped through the tubing and into the casing, was identified as one of the potential cost effective solution. The hardened cement then acts as a barrier to satisfy operating guidelines. The reservoir was then additionally perforated, flow tested and successfully monetized. Prior to well entry, tubing and casing integrity tests were performed to confirm the integrity. This step is critical to ensure that cement will only flow into the casing where the tubing was punched. Once the cement is hardened, pressure test from the tubing and from the casing indicated the cement has effectively isolated both tubulars. Subsequent Cement Bond Log and Ultrasonic Imaging Tool also displayed nearly 120m of fair to good cement above the target perforation depth. These data served as basis and proof that the cement packer was solid and the reservoir was ready for additional perforation. Taking into account the relatively poor reservoir quality, it was decided to perforate the reservoir twice with the biggest gun available to increase the probability of maximum reservoir contact while minimizing skin. Post perforation, a sharp increase in the tubing pressure was observed, indicating pressure influx from the reservoir. The casing pressure however, remained low, confirming no tubing-casing communication and thus the success of the cement packer. The well was later able to unload naturally from the high reservoir pressure. The work program also managed to confirm the producibility of the reservoirs. This successful approach has opened up potential application to similar stranded reservoirs behind casing.

Research on the mechanism of the influence of flooding on the killing of empty wells

In empty well killing, in order to save the time and cost of killing the well, the dynamic replacement method is often used to kill the well. The main problem of the dynamic replacement method for killing wells is how to avoid terrible working conditions caused by flooding, such as gas carrying fluid, killing fluid being brought to the wellhead. Based on the principle of flooding formation and the basic tenets of flooding correlation experiment and dynamic replacement method, this paper incorporates the kill fluid viscosity, surface tension, droplet diameter, inclination angle, drill pipe joint outer diameter, and drill pipe eccentricity into the calculation range and establishes a new mathematical model suitable for dynamic replacement kill. Based on the calculation results, the influencing factors of flooding are analyzed, and the following conclusions are drawn: the increase of dynamic viscosity, gas density in the well, casing pressure, well angle, the outside diameter of drill pipe, the outer diameter of drill pipe joint, and eccentricity of drill pipe can promote the occurrence of flooding; The increase of surface tension, well-killing fluid density, and casing inner diameter have an obstacle to flooding.

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.