Unlocking Marginal Resources through Synergy between Subsurface and Surface Entities

2021 ◽  
Author(s):  
Ronald Atasi ◽  
Albertino Prabowo ◽  
Mitterank Siboro
Keyword(s):  
Corrosion Rate ◽  
History Matching ◽  
Unit Cost ◽  
Development Project ◽  
East Kalimantan ◽  
Cumulative Production ◽  
Well Development ◽  
Gas Fields ◽  
Mahakam Delta ◽  
Pipeline Design

Abstract Tunu is one of the biggest gas fields in Indonesia with 1400 km2 area in Mahakam Delta, East Kalimantan. This field has been producing since 1990 with cumulative production of more than 9.5 tcf and 190 mbbl condensate by the end of 2020 from over 1000 operating wells. Today, Tunu field contributes for approximately 40% of Mahakam production. After 30 years of production, Tunu production level is currently in declining phase, shown by its yearly production profile which exhibits a declining trend since 2008. Furthermore, Tunu well development project was considered marginally economical due to depleting reserve per well. Thus, an integrated study was conducted in order to reduce surface expenditure cost of Tunu pipeline based on current operating parameters. The study consisted of WHSIP history matching to determine new pipeline design pressure, evaluation of future wells production lifetime, and adjustment of pipeline corrosion allowance based on actual corrosion rate observed in Tunu field. Results show that most of future Tunu wells are predicted to have WHSIP below 200 barg and 1.5 to 3 years’ production lifetime. Corrosion rate in Tunu field as measured using corrosion coupon in piping with corrosion inhibitor injection is found to be less than 1 mm/20 years. Therefore, corrosion allowance for Tunu pipeline is optimized from 5 to 3 mm for 10-years design lifetime. For exceptional circumstances where actual well WHSIP > 200 barg, other method of producing the well will be implemented. Hence, by integrating recent subsurface behavior (WHSIP and well lifetime) with surface understanding (corrosion rate), it was then proposed new pipeline design for Tunu development. This study has generated USD 13 million cost saving for pipeline procurement in 2020. Moreover, implementation of the new pipeline design reduces 40% of pipeline unit cost for future pipeline procurement. This study has become the basis for future well development projects in Tunu field which significantly prolong Mahakam's production sustainability.

Unlocking Oil Resources without Artificial Lift Using Testing Barge in Tambora Gas Field

2020 ◽  
Author(s):  
J., A. Anggoro
Keyword(s):  
Oil Recovery ◽  
Gas Field ◽  
Artificial Lift ◽  
Oil Resources ◽  
Cumulative Production ◽  
Inspection And Maintenance ◽  
Routine Inspection ◽  
Prime Condition ◽  
Safety Operation ◽  
Mahakam Delta

Tambora field is a mature gas field located in a swamp area of Mahakam delta without artificial lift. The main objective of this project is to unlock existing oil resources. Most oil wells could not flow because there is no artificial lift, moreover the network pressure is still at Medium Pressure (20 Barg). Given the significant stakes, the option to operate the testing barge continuously as lifting tool is reviewed. The idea is to set the separator pressure to 1-3 Barg, so that the wellhead flowing pressure could be reduced to more than 15 Barg which will create higher drawdown in front of the reservoir. The oil flows from the reservoir into the gauge tank, where it is then returned to the production line by transfer pumps. The trial was performed in well T-1 for a week in November 2017 and successfully produced continuous oil with a stable rate of 1000 bbls/d. What makes this project unique is the continuous operation for a long period of time. Therefore, it is important to ensure the capacity of the gauge tank and the transfer pump compatibility with the rate from the well, the system durability which required routine inspection and maintenance to ensure the testing barge unit is in prime condition and to maintain vigilance and responsiveness of personnel. This project started in 2018 for several wells and the cumulative production up to January 2020 has reached 158 k bbls and will be continued as there are still potential oil resources to be unlocked. Innovation does not need to be rocket science. Significant oil recovery can be achieved with a simple approach considering all safety operation, production and economic aspect.

The geosolitonic concept of high output hydrocarbon deposits formation

2021 ◽  
pp. 13-22
Author(s):  
R. M. Bembel ◽  
S. R. Bembel ◽  
M. I. Zaboeva ◽  
E. E. Levitina
Keyword(s):  
Western Siberia ◽  
Oil And Gas ◽  
Chemical Elements ◽  
Seismic Exploration ◽  
Oil And Gas Fields ◽  
Recoverable Reserves ◽  
Production Wells ◽  
Cumulative Production ◽  
Gas Fields ◽  
Hydrocarbon Deposits

Based on the well-known results of studies of the ether-geosoliton concept of the growing Earth, the article presents the conclusions that made it possible to propose a model of thermonuclear synthesis of chemical elements that form renewable reserves of developed oil and gas fields. It was revealed that local zones of abnormally high production rates of production wells and, accordingly, large cumulative production at developed fields in Western Siberia are due to the restoration of recoverable reserves due to geosoliton degassing. Therefore, when interpreting the results of geological and geophysical studies, it is necessary to pay attention to the identified geosoliton degassing channels, since in the works of R. M. Bembel and others found that they contributed to the formation of a number of hydrocarbon deposits in Western Siberia. When interpreting the results of geological-geophysical and physicochemical studies of the fields being developed, it is recommended to study the data of the ring high-resolution seismic exploration technology in order to identify unique areas of renewable reserves, which can significantly increase the component yield of hydrocarbon deposits.

First Application Drilling New Wells with HWU in Swamp Environment, Mahakam Delta

2021 ◽  
Author(s):  
R. A. S Wijaya
Keyword(s):  
Drilling Rate ◽  
Shallow Gas ◽  
Field Development ◽  
Drilling Rig ◽  
East Kalimantan ◽  
Well Location ◽  
Shallow Wells ◽  
Drilling Unit ◽  
Mature Field ◽  
Mahakam Delta

Tunu is a mature giant gas and condensate field locate in Swamp Area on Mahakam Delta, East Kalimantan, Indonesia. The field has been in developed for more than 40 years and considered as a mature field. As mature field, finding an economic well has become more challenging nowadays. The deeper zone of Tunu (TMZ) has no longer been considered profitable to be produced and the focus is shifted more on the producing widespread shallow gas pocket located in the much shallower zone of Tunu (TSZ). Facing the challenge of marginal reserves in the mature field, Pertamina Hulu Mahakam (PHM) take two approaches of reducing well cost thus increase well economics, improving drilling efficiency and alternative drilling means. Continues improvement on drilling efficiency by batch drilling, maxi drill, maximizing offline activities and industrialization of one phase well architecture has significantly squeezed the well duration. The last achievement is completing shallow well in 2.125 days from average of 6.5 days in period of 2017-2019. Utilization of Swamp Barge Drilling Rig on swamp area had been started from the beginning of the field development in 1980. Having both lighter and smaller drilling unit as alternative drilling means will give opportunity of reducing daily drilling rate. Hydraulic Workover Unit (HWU) comes as the best alternative drilling means for swamp area. In addition, fewer and smaller footprint equipment requires smaller barges with purpose of less civil works to dredge the river and preparing well location. Drilling with HWU project has been implemented at Tunu area with 5 wells has been completed successfully and safely. HWU drilling concept considered as proven alternative drilling means for the future of shallow wells development.

One Phase Well OPW : Unlock Shallow Reservoir Efficient and Economically by Eliminating Surface Casing

2021 ◽  
Author(s):  
Irfan Hanif ◽  
Bramarandhito Sayogyo ◽  
R Riko ◽  
Praja Hadistira ◽  
Karina Sari
Keyword(s):  
Shallow Gas ◽  
Two Phase ◽  
East Kalimantan ◽  
Drilling Operations ◽  
The Common ◽  
Mature Field ◽  
The Cost ◽  
Mahakam Delta ◽  
Common Architecture ◽  
Drilling Time

Abstract Tunu is a mature giant gas and condensate field locate in Mahakam Delta, East Kalimantan, Indonesia. The field has been in development for almost 30 years and currently has been considered as a mature field where to put a state of an economic well has become more challenging nowadays. The deeper zone of Tunu has no longer been considered as profitable to be produced and the current focus is more on the widespread shallow gas pocket located in the much shallower zone of Tunu. One phase well is architecture without 9-5/8" surface casing. OPW is one-section drilling using a diverter mode from surface to TD without using BOP. Historical for OPW is began from 2018, where drilling reservoir section using diverter mode in two-phase. In 2018 also succeeded in performing perforated surface casing. Due successfully in drilling operation using diverter and perforated surface casing, in 2019 drilling trials for OPW were carried out. Until now, the OPW architecture has become one of the common architecture used in drilling operations as an optimization effort. Until December 2020 PHM has completed 15+ OPW wells. A general comparison of OPW and SLA well is at the cost of constructing a well of approximately 200,000 - 300,000 US$. The disadvantages of OPW wells are more expensive in the mud and cement section when using a 9-1/2" hole, but in terms of the duration, OPW drilling time is more efficient up to 2-3 days. If viewed from the integrity of the OPW wells, from 15 OPW wells that have been completed, only 2 of them have SCP.

Application Investigation of Light Proppant in Hydraulic Fracturing of Marcellus Shale

2021 ◽  
Author(s):  
Aymen Alhemdi ◽  
Ming Gu
Keyword(s):  
History Matching ◽  
Marcellus Shale ◽  
In Situ Stress ◽  
Production Performance ◽  
Well Performance ◽  
Fracture Permeability ◽  
Fracture Conductivity ◽  
Stimulated Reservoir Volume ◽  
Conductivity Distribution ◽  
Cumulative Production

Abstract Slickwater-sand fracturing design is widely employed in Marcellus shale. The slickwater- sand creates long skinny fractures and maximizes the stimulated reservoir volume (SRV). However, due to the fast settling of sand in the water, lots of upper and deeper areas are not sufficiently propped. Reducing sand size can lead to insufficient fracture conductivity. This study proposes to use three candidate ultra-lightweight proppants ULWPs to enhance the fractured well performance in unconventional reservoirs. In step 1, the current sand pumping design is input into an in-house P3D fracture propagation simulator to estimate the fracture geometry and proppant concentrations. Next, the distribution of proppant concentration converts to conductivity and then to fracture permeability. In the third step, the fracture permeability from the second step is input into a reservoir simulator to predict the cumulative production for history matching and calibration. In step 4, the three ULWPs are used to replace the sand in the frac simulator to get new frac geometry and conductivity distribution and then import them in reservoir model for production evaluation. Before this study, the three ULWPs have already been tested in the lab to obtain their long-term conductivities under in-situ stress conditions. The conductivity distribution and production performance are analyzed and investigated. The induced fracture size and location of the produced layer for the current target well play a fundamental effect on ultra-light proppant productivity. The average conductivity of ULWPs with mesh 40/70 is larger and symmetric along the fracture except for a few places. However, ULWPs with mesh 100 generates low average conductivity and create a peak conductivity in limited areas. The ULW-3 tends to have less cumulative production compared with the other ULWPs. For this Marcellus Shale study, the advantages of ultra-lightweight proppant are restricted and reduced because the upward fracture height growth is enormous. And with the presence of the hydrocarbon layer is at the bottom of the fracture, making a large proportion of ULWPs occupies areas that are not productive places. The current study provides a guidance for operators in Marcellus Shale to determine (1) If the ULWP can benefit the current shale well treated by sand, (2) what type of ULWP should be used, and (3) given a certain type of ULWP, what is the optimum pumping schedule and staging/perforating design to maximize the well productivity. The similar workflow can be expanded to evaluate the economic potential of different ULWPs in any other unconventional field.

The Vale of Pickering gas fields: Kirby Misperton, Malton, Marishes and Pickering, North Yorkshire, UK Onshore

2020 ◽  
Vol 52 (1) ◽  
pp. 82-93 ◽  
Author(s):  
D. Harrison ◽  
M. Haarhoff ◽  
M. Heath-Clarke ◽  
W. Hodgson ◽  
F. Hughes ◽  
...  
Keyword(s):  
Seismic Data ◽  
Gas Flow ◽  
Lower Carboniferous ◽  
Gas Recovery ◽  
Water Influx ◽  
Water Breakthrough ◽  
Artificial Lift ◽  
Cumulative Production ◽  
Gas Fields ◽  
3D Seismic Data

AbstractThe Vale of Pickering gas fields were discovered over a 20-year period. The development scheme was aimed to deliver 9.3 MMscfd gas to the Knapton Power Station nearby. Cumulative production is 30.3 bcf from an estimated 172 bcf gas initially in place. The gas fields comprise a series of low relief structures at depths around 5000 ft true depth subsea. The primary reservoir is Zechstein Group dolomitized and fractured carbonates of the Permian Kirkham Abbey Formation with average reservoir quality ranges of 12–13% porosity and 0.5–1.5 mD permeability. Secondary reservoirs exist in Carboniferous sandstones directly below the Base Permian Unconformity. The gas is sourced from Lower Carboniferous shales. The fields were discovered using 2D seismic data and subsequent 3D seismic data have been merged to form a 260 km2 dataset. Zechstein production has been limited by early water breakthrough. Artificial lift is planned to enhance the gas flow rate on the Pickering Field and anticipated water influx will be re-injected. If this enhanced gas recovery scheme is successful it can be applied to the other fields. Plans to hydraulically fracture a number of zones in the Carboniferous Lower Bowland Section are in progress.

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