Open Hole Multistage Completion Exceeds Production Expectations from South Sulige Gas Field in China

Shunted screen gravel packing is a kind of technology which is difficult to complete gravel packing with the conventional method in low fracture pressure formation and long wellbore length condition. According to the characteristics of LS 17-2 deepwater gas field, the shunted screen packing tool was designed and the gravel packing process and packing mechanism were analyzed. The variation law of the flow friction, flow rate distribution in multichannel, and other parameters of the shunted screen gravel packing were analyzed and calculated. The friction calculation model of different stages of gravel packing was established. A gravel packing simulation software was developed to simulate the friction in different stages of shunted screen gravel packing. The parameters such as sand-dune ratio, pumping sand amount, packing length, and packing time in the process of packing were also calculated. In deepwater horizontal well gravel packing, the results show that the friction ratio of the string is the largest in the stage of injection and α-wave packing. While the friction increases rapidly in the stage of β-wave packing because the carrier fluid needs to flow through the long and narrow washpipe/screen annulus. Particularly when the β-wave packing is near the beginning of the open hole, the packing pressure reaches the maximum. The calculated results are in good agreement with the measured results of the downhole pressure gauge. The model and software can provide technical support for the prediction and optimization of gravel packing parameters in the future.

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Numerical Simulation of Erosion Wear of Liquid-Solid Two-Phase Flow in Sliding Sleeve of Horizontal Well

Advanced Materials Research ◽

10.4028/www.scientific.net/amr.988.483 ◽

2014 ◽

Vol 988 ◽

pp. 483-488

Author(s):

Kun Ding ◽

Jian Min Li ◽

Wen Xin Yang ◽

Jian Hu ◽

Wei Zeng

Keyword(s):

Particle Size ◽

Horizontal Well ◽

Erosion Wear ◽

Construction Process ◽

Two Phase ◽

Gas Field ◽

Open Hole ◽

Important Means ◽

Oil Gas ◽

Dynamics Method

In recent years, the pitching sliding sleeve staged fracturing technology of open hole packer of horizontal well is widely used in shale gas, dense reservoirs, low permeable reservoirs and other exploration and development fields, and becomes the important means of present oil-gas field stimulation. But in the construction process of horizontal well fracturing, the abnormal condition that the sliding sleeve is not opened or is opened invisibly is occurred repeatedly, which has big impact on the fracturing construction. Based on fluid dynamics method and Finnie micro-cutting theory, this paper simulated the erosion wear rate of ball seat at the different fracturing segments. The results showed that: the construction displacement has big impact on the erosion wear, followed by the particle size of proppant and sand ratio, wherein the erosion wear is in inversely proportional to the particle size of proppant; and when multistage fracturing, the possibility that the sliding sleeve close to the toe end and heel happens erosion destruction is much less than that of sliding sleeve in the middle.

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

10.2118/206172-ms ◽

2021 ◽

Author(s):

Rahmawan Rena ◽

Ewan Robb ◽

Ibnu Maulana ◽

Aswin Batubara ◽

Yulia Yulia ◽

...

Keyword(s):

Cost Savings ◽

High Rate ◽

Well Testing ◽

Gas Field ◽

Field Development ◽

Coiled Tubing ◽

Central Java ◽

Open Hole ◽

Seal Assembly ◽

Strategic Project

Abstract 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.

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Innovative Approach to Drilling Across Highly Fractured Formation in the Biggest Deep Gas Field in the Middle East

10.2118/202173-ms ◽

2021 ◽

Author(s):

Efe Mulumba Ovwigho

Keyword(s):

Risk Assessment ◽

Middle East ◽

Current Drive ◽

Successful Implementation ◽

Prevention Measures ◽

Gas Field ◽

Time Saving ◽

Well Control ◽

Carbonate Formation ◽

Open Hole

Abstract On a Deep Gas Field in the Middle East, it is required to drill across a highly fractured and faulted carbonate formation. In most wells drilled across the flank of this field, it is impossible to cure the encountered losses with conventional or engineered solutions. Average time to cure losses is 20 days. With the current drive for cost optimization, it has become necessary to eliminate the NPT associated with curing the losses. A thorough risk assessment was conducted for wells drilled on the flank of this field, it was established that the risk of encountering total losses was very high. Seismic studies were performed and it was observed it would be impossible to eliminate total losses as fractures were propagated in all directions. It was proposed to run a sacrificial open hole bridge plug above the loss zone and sidetrack the well instead of performing extensive remedial operations. The proposed solution would help eliminate the well control and HSE risks associated with drilling blindly ahead with the reservoir formation exposed. Applied the proposed solution on the next well that was drilled on the flank of the field, encountered total losses, spotted eight LCM pills, unable to cure the losses, ran sacrificial open hole bridge plug and sidetracked the well. The entire process was completed in 30 hours. Sidetracked the well in adjacent direction to the initial planned well trajectory based on further seismic data analysis and no losses was encountered. Recovered full mud column to surface thus ensuring the restoration of all well barrier elements. This solution has since been adopted as best practice for wells drilled on the flank of the field where there is high probability of encountering total losses. The average time saving per well due to this optimized solution is 450 hours for wells where total losses are encountered. This engineered solution has made drilling wells on the flank of the field in a timely manner possible and at optimized costs. This has resulted in: –The elimination of Non-Productive Time,–Quick delivery of the well to production,–Reduced HSE risk,–Reduced well control risk as loss zone is quickly isolated before drilling ahead. This paper will explain why running sacrificial open hole bridge plugs and sidetracking the well is a more effective solution compared to extended remedial operations when total losses are encountered while drilling across highly fractured / faulted formation. It will discuss the extensive risk assessment conducted, the mitigation and prevention measures that were put in place in order to ensure successful implementation on trial well.

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Success story of integrated subsurface study to deliver a successful infill drilling: Buntal-5 case study

10.29118/ipa21-e-132 ◽

2021 ◽

Author(s):

B. Khoironi

Keyword(s):

History Matching ◽

Gas Field ◽

Water Contact ◽

Seismic Amplitude ◽

Water Breakthrough ◽

Geological Features ◽

Open Hole ◽

Geophysical Study ◽

Infill Drilling ◽

Geological Concept

Buntal is a mature gas field located in South Natuna Sea Block B PSC. The field was discovered by well Buntal-1 and delineated by appraisal well Buntal-2. The field consists of multi-stacked sandstone reservoirs, which were deposited under fluvial deltaic environment. The major Buntal reservoirs have been produced since 2004 from two subsea wells. Buntal-3 was producing from zones Beta-1 and Beta-2, while Buntal-4 was a horizontal well producing from Zone-1C. Both of those wells had loaded up prior to Buntal-5 drilling. This paper describes the details of a multidisciplinary approach taken for the proposal of Buntal-5 infill drilling. An integrated geological and geophysical study were carried out to quantify resources and uncertainties of the remaining thin unproduced zones. In total, there are 8 virgin zones as Buntal-5 initial target namely Beta-0, Zone-1A, Zone-1B, Zone-1D, Zone-1E, Zone-2B, Zone-3 and Zone-3A. Max-trough seismic amplitude was utilized to identify geological features across for each Buntal reservoir. The result was then combined with geological concept based on its depositional environment to justify a reasonably higher hydrocarbon volume which can not be estimated only by wells’ data. A reservoir simulation study was also carried out to not only to evaluate production potential from the virgin zones but also to capture upside potential from the produced zones. Simulation history matching result on Zone-1C revealed early water breakthrough experienced by Buntal-4 well due to water cresting phenomena which left significant gas reserves. This result added upside potential to Buntal-5 which initially only targeted marginal remaining unproduced zones. The well was drilled at the end of 2019 and proven to be a major success. Buntal-5 open hole logs data indicate thicker and better virgin zones reservoir quality as expected by integrated geological and geophysical study. Furthermore, significant remaining gas was encountered in Zone-1C with actual gas water contact was within the simulation result proving the water cresting theory, the zone itself add well’s gas-in-place by 30% on top of the unproduced zones’ gas-in-place.

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