Deployment of Downhole Hydraulic Lubricator Valve Enables Safe and Efficient Perforating and Production Testing Strategy – Case Study in Jambaran High Rate Gas Field, Indonesia

This paper details the first implementation of a deep-set downhole hydraulic lubricator valve (DHLV) in Indonesia. This application was implemented in Jambaran field, onshore Central Java as part of Jambaran-Tiung Biru (JTB) national strategic project. Jambaran is a large carbonate gas field development located in proximity to densely populated areas. Since the field's reservoir contains significant concentrations of CO2 and H2S, it was important to design the completions to be able to perforate and test the wells safely without endangering the surrounding area. To produce as per reservoir management strategy, 800 ft of reservoir section drainage was required. Multiple completion designs were considered in the initial stages which included consideration of an open hole completions design, multiple wireline perforating runs and a cased hole live well single trip coiled tubing gun system. The rigless single trip coiled tubing gun deployment system was chosen due to safety and efficiency factors. With a deep set DHLV as the primary barrier in controlling the wells following perforating substantial daily rental cost savings can be realized during perforating operations. JTB field was developed by drilling 5 new well plus 1 re-entry well. The completions design was similar in all 6 wells. A 2 step completion design was utilized, to compensate for life of well tubing movement load, this consisted of a polished bore receptacle and production packer assembly in the lower completion. The 2nd stage of the completion consisted of 7" × 5-1/2" tubing with Tubing Retrievable Safety Valve (TRSV), DHLV, Permanent Downhole Gauge (PDHG) and production seal assembly. Strategically placing the PDHG below the DHLV enabled monitoring of bottom hole pressure during shut in without use of memory gauges validating the DHLV as primary barrier during gun retrieval. The production seal assembly was tied back into the lower polished bore receptacle that was previously set. The deep-set DHLV enabled the operator to (i) safely run long TCP gun assemblies up to 911 ft of gross gun length per well to perforate the whole well in 1 trip, (ii) POOH guns efficiently with one time bleed off (iii) efficiently initiate the pressure build up phase by shutting in the well against the DHLV as opposed to a surface valve prior to flowing the well and (iv) gun assemblies retrieved without the need to kill the well. After completing and well testing all 6 wells, the benefits of implementing the deep-set DHLV was immediately realized. By perforating underbalanced, omitting the well kill process and immediately proceeding with pressure build up by closing the DHLV resulted in operator savings of approximately 1.5 million USD over the entire rigless completion campaign.

Development and Application of 140 MPa Mandrel Casing Head in Ultra-High Pressure Gas Well

In view of the high shut in pressure of gas wells in Kuqa mountain front ultra-high pressure block where the highest shut in pressure of KeS X is 115MPa, the 105MPa casing head currently used can not meet the shut in demanding, so the risk of well control is high. A new 140MPa mandrel casing head was developed. Its sealing structure adopts the form of X Metal sealing at the upper end and rubber seal at the lower end, which has the characteristics of high pressure bearing and reliable sealing performance. The structural design verification of the 140 MPa mandrel casing head was conducted by finite element analysis(FEA) of the structural strength and sealing performance of the key components of the casing head, including casing head body and hanger. Then indoor evaluation tests were carried out on the material, strength and sealing performance of the casing head and hanger, as well as the overall structure, and the 140MPa mandrel casing is completed Finally, the quality control level of 140MPa mandrel casing head product has reached the requirements of ultra-high pressure field working condition through field trial in ultra-high pressure gas well, and it has the conditions for promotion and application in other ultra-high pressure gas wells. The results of and FEA show that the maximum bearing capacity of the mandrel type casing head is 793t, and no yielding occurs under the conditions of bearing capacity of 473t, external pressure of 140MPa and safety factor of 1.35; the maximum internal pressure resistance of the hanger is 212MPa, and no yielding occurs under the conditions of bearing capacity of 200t, internal pressure of 140MPa and safety factor of 1.35. The indoor evaluation test shows that: ① there is no sulfide stress cracking (SSC) and hydrogen induced cracking (HIC) in the casing head body (0Cr18Ni9) and hanger (718); ② there is no leakage in the casing head body under 210MPa clean water and hanger under 140MPa nitrogen; ③ there is no yield in the casing head step and hanger under 673t pressure in the mandrel type casing head. The field test shows that the test pressure of the mandrel type casing head is 117MPa and it is qualified under 280t setting and hanging tonnage. At present, the 140 MPa mandrel casing head has been successfully used in Kuqa mountain for 15 wells, which provides a reliable guarantee for the safety production of ultra-high pressure gas wells. The 140MPa mandrel casing head developed in this paper has the following three innovations: ① adopt the structure without top wire, fix the wear-resistant sleeve by installing the top wire flange during drilling, and avoid the leakage caused by the top wire hole in the later production; ② adopt the form of upper metal seal + lower X-type rubber seal in the sealing structure of hanger, which can not only avoid the metal seal of hanger during the lowering process The seal assembly is damaged and fails, and in case of unqualified pressure test, the metal seal assembly at the upper end of the hanger can be replaced; ③ a limited step is designed at the contact part between the metal seal assembly at the upper end of the mandrel hanger and the casing head body, which can transfer the excess pressure to the casing head body, so as to avoid the failure of the rubber seal and bearing step at the lower part of the hanger.

Well Integrity Issues in Steam Flood Injection Wells, Karim Small Field Cluster

Two (2) steam flood vertical injection wells are under operation for the last 15 months in a two- pattern pilot. Previous steam injection experience in this reservoir did not indicate serious issues due to the short injection periods for cyclic steam stimulation (CSS) but several well integrity issues have been faced during the steam flood period. Key issues include high wellhead growth, steam leak to the annulus A, annulus between 7” production casing and 4-1/2” injection tubing, and groundwater vapor behind 9.625” surface casing. Negative impacts from these issues on the continuity and effectiveness of the steam flood are recognized and need to be resolved comprehensively. All wells in the steam flood pilot were drilled and completed based on designs and procedures according to thermal well compliance including well equipment, and cementing specification. Production casing was equipped with thermal expansion collars to support reduction in wellhead growth. Completion strategy uses seal bore packer with bore extensions to accommodate tubing movement and Vacuum-Insulated-Tubing to provide maximum thermal insulation. However, the presence of a total- loss zone near the surface (starting from 50 m depth) affects the cement isolation between surface casing and 12.25” open hole. Daily monitoring is performed on each well where key injection parameters and well responses are recorded. Maximum wellhead growth reached 61 cm within the first week and steam leak from the injection string to annulus A started after 6 months of steam injection. Soon after that, groundwater vapor starts to arise from the gap between 9.625” casing and 12.25” open hole. These series of failures occurred in both injection wells within 3 months apart from each other. It is believed that the steam leak to annulus A resulted in thermal transmission to groundwater vapor. Hoist entries to both injectors indicated that Injector-1 has tubing seal assembly stuck inside seal bore and resulted in parted tubing collar while Injector-2 has tubing seal assembly damage. Both wells have thick oil covering the retrieved seal bore packer. Remedial actions were performed, including a complete change-out of the seal bore packer assembly and top-job cement fill up to surface using fast-set cement to isolate the gap between 9.625” casing and 12.25” open hole to reduce wellhead growth. As a result, the maximum wellhead growth became only 19 cm and 4 cm in Injector-1 and Injector-2, respectively. These remedial actions also led to restoring well and thermal integrity. Retrieved seal bore packer was sent back to manufacturer for appropriate failure analysis and providing useful feedback reports on the above issues. Monitoring and observation data along with failure analysis should provide vital information and possible improvement in completion strategy for steam injection wells that are planned for continuous steam flood projects in similar reservoirs.