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Umar, Khalid (PT Pertamina Hulu Mahakam) | Rahman, Risal (PT Pertamina Hulu Mahakam) | Hidayat, Reyhan (PT Pertamina Hulu Mahakam) | Kurniawati, Pratika Siamsyah (PT Pertamina Hulu Mahakam) | Marindha, Rantoe (PT Pertamina Hulu Mahakam) | Dahnil, Gitani Tsalitsah (PT Pertamina Hulu Mahakam) | Sobirin, Muhammad (PT Pertamina Hulu Mahakam) | Priyono, Subur (PT Pertamina Hulu Mahakam) | Susilo, Didik (PT Pertamina Hulu Mahakam) | Surahman, Adi (PT Pertamina Hulu Mahakam) | Setyaji, Irwan (PT Pertamina Hulu Mahakam) | Adibawa, Ngurah Candra (PT Pertamina Hulu Mahakam) | Smaz, Nasuto (PT Pertamina Hulu Mahakam) | Safitri, Yufa (PT Pertamina Hulu Mahakam) | Setiawan, Dodi (PT Pertamina Hulu Mahakam) | Handoko, Bayu Setyo (PT Pertamina Hulu Mahakam) | Hidayat, Danny (PT Pertamina Hulu Mahakam)
Abstract The objective of this paper is to present the well revival strategy for gravel pack completion with liquid loading issue. Well NB-X is a high deviated gas well which was completed with 2 Sliding Sleeve Door-Gravel Pack (SSD-GP) zones and tubingless section. Since this well is a gas well with high water production, sudden unplanned shutdown can lead to a liquid loading issue. Revival well strategy by offloading the well to atmospheric was still not able to recover production as before the shutdown due to the high liquid column in the well. Therefore, a well intervention operation is needed to revive the well. The strategy was initiated by conducting a bottom hole monitoring survey to identify water sources. Production Logging Tool (PLT) was used to precisely monitor pressure, temperature, water holdup, and fluid rate along the wellbore for further water source and production allocation analysis. Once the water source zones have been identified, GP zone change for water shut-off (WSO) operation was requested. There are several means to execute zone change and unloading that are commonly used in Offshore Mahakam field each of which has selective economic consideration based on the expected well potential. A comparative study both for zone change (slickline, electricline tractor-stroker, and coiled tubing) and unload (N2 injection with coiled tubing) is performed to decide the most efficient way to revive the well. Operations started with a slickline zone change to close the water zone followed by production logging, however due to high inclination, it was found that the target zone was not fully closed. Based on the comparative study, zone change and unloading with coiled tubing (CT) was the most efficient strategy with cost saving for about 83% compared to the other means. Zone change and unloading can safely and efficiently be performed with CT followed by a production test via Multi-Phase Flow Meter (MPFM) while keeping the CT string inside the tubing to perform as a velocity string until gas production target is obtained. Well revival strategy on well NB-X was proven to be able to revive 100% well production of 18 MMscfd within a very short time period from the shutdown event. Comparative study between coiled tubing and electricline tractor-stroker for zone change and unloading was critical since the offshore area have many challenges such as unpredictable weather, limited availability of transportation units, efficiency of setting up units from and to the platform, and also the callout cost both for the equipment and personnel between the two which ends with the selection of coiled tubing as the most efficient way for this case.
Artificial lift is a method used to lower the producing bottomhole pressure on a formation to obtain a higher production rate from the well. This can be done either with a positive-displacement downhole pump, such as a beam pump or a progressive cavity pump (PCP), to lower the flowing pressure at the pump intake, or it can be done by injecting gas with high pressure through a downhole gauge near the bottom of the well. The selection of the method depends on many factors such as reservoir characterization, completion design, and operating conditions such as pressure, temperature, and producing rate. In addition, production-fluid properties such as density and viscosity also play a role in the selection of artificial-lift methods. The market for artificial-lift systems is growing at a compound annual growth rate of more than 4.5% (Figure 1).
Setiadi, Rahman (Pertamina Hulu Mahakam) | Dharma, Erlangga Surya (Pertamina Hulu Mahakam) | Jackson, Steven Richard (3M) | Gundemoni, Bhargava Ram (3M) | Dwitama, Sakti (Pertamina Hulu Mahakam) | Umar, Khalid (Pertamina Hulu Mahakam) | Suprapto, Edy (Pertamina Hulu Mahakam) | Gunawan, Gany (Pertamina Hulu Mahakam) | Ashfahani, Adnan Syarafi (Pertamina Hulu Mahakam) | Ramadhana, Zulmi (Pertamina Hulu Mahakam) | Nugroho, Triantoro Adi (Pertamina Hulu Mahakam) | Australianda, Edo Rizky (Pertamina Hulu Mahakam)
Abstract Mahakam block has supported Indonesia's Oil and Gas production with over 40 years of deliverability. Presently, along with its maturity cycle, comes the challenge of a steeply declining matured field with indicators of marginal reserves, included unconsolidated sand reservoirs as one of the main contributors which required sand control. In addition, future offshore platform development emerged the urgency of light deployment and robust sand control. Deep dive into the methodology, it was mandatorily to revisit what techniques available on the shelves and what is the current technology has to offer. Mahakam subsurface sand controls were classified into gravel pack, open hole stand-alone screen, chemical sand consolidation (SCON), and thru-tubing metal screen. These also respectively account for the highest to the lowest of operational investment, associated production contribution, and its reliability. Thru tubing screen methodology in cased-hole application showed weakness by plugging and erosion issue resulting on minimum utilization as lowest end subsurface sand control means. Several normative elements factored into it, with the root cause of screen placement. It was avoided to install metallic screen in front perforation due to direct jetting during the natural sand packing (NSP) process, causing an installation at slightly above perforation with the absence of stable NSP and screen size selection complexity. Thru-tubing screen with higher strata of material, silicon carbide or ceramic, was selected as a pioneer on new installation philosophy to tackle erosion issue. It was combined with the developed Mahakam sand grain size map as a screen size selection guideline. A confidence pseudo-straddle thru-tubing ceramic screen (TTCS) installation campaign in front of perforation interval was explored on swamp (Tunu) and offshore (Peciko) gas wells. This technique adopts open hole SAS with retrievable concept optimizing slickline intervention. Perfection of the techniques is a process that continues. However, based on the current study and trial results on wells installation throughout 2020 to 2021, positive results were achieved: Operation simplicity with minimum operation HSE risk, Sand free production delivery addressing highly unconsolidated reservoir with widely distributed sand grain by mitigating the risk of screen erosion, The average cost savings were 66% in delta and 76% in offshore compared to allocated SCON budget, Cummulative gas deliverability increased by more than 200% compared to previous thru-tubing metal screen performance, Performance exceeded average SCON production rate and in-situ gas velocity limit at several installations, The installation method had a 100% retrievability success ratio from all retrieval attempts on inactive wells installation, It had no damaging effect to the reservoir when remedial by SCON was required, The installation concept adoption has been proven on highly deviated and unique completion configurations. This enlightenment boosted confidence in both the assessment technique and installation philosophy. This initiative would enable the production of Mahakam marginal sandy reservoir while sparking to a wider application as an alternative robust and light sand control solution.
Setiadi, Rahman (Pertamina Hulu Mahakam) | Jong, Yulianto (Pertamina Hulu Mahakam) | Mahfudhin, Nur (Pertamina Hulu Mahakam) | Muwaffaqih, Mutawif Ilmi (Pertamina Hulu Mahakam) | Dading, Albert Richal (Pertamina Hulu Mahakam)
Abstract Tunu is one of Mahakam fields with majority gas production. The depositional nature of fluvial with minimum tidal influence results in the signature of delta sedimentation by hundred layers of gas-bearing sand lenses as pay zone. They are constructed of unconsolidated clean and shaly sand reservoirs at the shallower burial and higher consolidation at deeper burial due to compaction and diagenesis. The unconsolidated section requires sand control as mandatory means to unlock it safely. The combined challenge of numerous sand layers and marginal reserves makes it economically impossible to perform regular detailed physical sand grain assessment by individual conventional coring completed with Laser Particle Sieve Analysis (LPSA). An economic approach is through performing sand bailing. However, the bailed sand dry-sieve results were confusing with wide particle size distribution (PSD) curve variation from several well samples. Referring to this PSD uncertainty, installing straddled thru-tubing screen in front of the reservoir as sand control resulted in good production and plugged indication at the beginning of the initiative by utilizing a similar screen opening size. Thus, a new fit-for-purpose methodology was required. A study to predict sand grain size on each reservoir target was initiated by analyzing three available shallow reservoir cores in Mahakam, which could cover most of Tunu's shallow sedimentation type. The result was that most of the sand grain size distribution on each sample core correlated with their calculated shale volume content (v-shale). Lower v-shale is respected to larger sand grain size. Unconsolidated Tunu Shallow reservoir doesn't contain any specific radioactive minerals. Thus, v-shale could be easily calculated from gamma-ray logs, which are always available on each reservoir target at any drilled wells. The relationship between sand grain size and v-shale was gathered on a single map. The map was then validated by historical screen installation. Positive results were seen when screen size selection respects specific patterns on the generated sand map at the v-shale value of perforation intervals. Thru-tubing screen installation campaign was continued following the new sand map reference. It could deliver more than 80% successful installation with no plugging or sand at a new perforated reservoir when no screen integrity issue due to erosion was encountered. This novel approach allowed better prediction of thru-tubing screen opening size requirements and perforation interval selection in Tunu unconsolidated reservoir and was successfully expanded in offshore Mahakam field at similar facies.
Hidayat, Reyhan (Pertamina Hulu Mahakam) | Kurniawati, Pratika Siamsyah (Pertamina Hulu Mahakam) | Kurniawan, Aries Taufiq (Pertamina Hulu Mahakam) | Setyaji, Irwan (Pertamina Hulu Mahakam) | Pancawisna, Gerardus Putra (Pertamina Hulu Mahakam) | Marindha, Rantoe (Pertamina Hulu Mahakam) | Umar, Khalid (Pertamina Hulu Mahakam) | Dahnil, Gitani Tsalitsah (Pertamina Hulu Mahakam) | Rahman, Risal (Pertamina Hulu Mahakam) | Jamal, Muhammad Nadrul (Pertamina Hulu Mahakam) | Safitri, Yufa (Pertamina Hulu Mahakam) | Azhar, Raden-Muhamad Prayuda (Pertamina Hulu Mahakam) | Lodiman, William (Schlumberger Geophysics Nusantara) | Syarif, Hibroni (Interwell)
Abstract Well N-1 in Mahakam Sisi Nubi field, East Kalimantan, had a problem with water and condensate production up to 11,000 BLPD which instantly rendered the production facility overwhelmed despite the high 34 MMSCD gas rate. To solve this, reservoir production profiling using production logging tool was first carried out. Selection of existing zone isolation method was then compared, yet none satisfies the challenges in this well due to restriction and cost issues. A relatively new technology, High Expansion (HEX) Straddle Packer, was introduced as another alternative. A series of engineering design and followed by operation design was then carried out to solve the well problem safely. A dummy tool run with 2.875" OD and 30ft of length passed through the restriction safely. Caliper logging observes reduction in tubing ID from 3.9" to 3.0". Temperature of the borehole reached 115 deg C at 3417 mBRT of this well. The two water producing zones were next to each other with a total top reservoir to bottom reservoir length of 11 m. With these values, a custom 2.7" straddle packer was built and tested to required temperature and passed. Production simulation with 0.7" ID, indicated the well could still flow over its critical flow regime. After installation, the well flows with 11 MMSCFD of gas with ~1800 BLPD liquid produced, a 83% reduction over previous liquid flowrate. Despite the well flows only 30% from initial gas rate, this well can now flow at an acceptable liquid rate. The successful installation of the first HEX Straddle expands the portfolio of mechanical water shut off methods in Mahakam and in Indonesia as this was the first HEX Straddle installed in Indonesia. Further study and replications are needed, yet this method can be a viable alternative if other has failed for wells with similar problems.
Abstract Mahakam Block is a huge oil and gas concession managed by PT. Pertamina Hulu Mahakam (PHM) and located in deltaic and offshore environment in East Kalimantan, Indonesia. Until today, the field has produced oil and gas for more than 50 years and categorized as "brown field" due to its declining production and marginal reserve potential. This condition has led to numerous effort to boost efficiency in well delivery from drilling perspective such that the reserve could be produced more economically. One of the effort that has been done to create a well to be more economical is by increasing the Rate of Penetration (ROP). An increase in ROP would directly impact on well duration that could be finished faster in such that it would also impact on much lower well cost. There are several key factors that influence ROP, yet the most crucial part is coming from drilling bit design that is used to drill the formation. Incompatibility between bit design with formation and directional drive type would often result in slow drilling progress and thus would make a well less profitable. To support this idea, the operator has launched a campaign called MAXIDRILL with aim to have a persistent excellent drilling performance from ROP perspective. Selective approach to different bit designs and bit suppliers has brought the operator to conduct the first trial in Indonesia utilizing a one inch PDC cutter drill bit. Besides the effort to increase well economics by increasing ROP using various bit designs through MAXIDRILL Campaign, PHM also tries to implement new set of well architecture dedicated specifically for developing the shallow hydrocarbon zone in Mahakam in general, and in Tunu Field in particular. With this new type of architecture, it allows drilling with 9-1/2″ hole to be done straight from 20″ Conductor Pipe down to well final target depth in single phase, where next 3-1/2″ production tubing will be run and cemented in place. The new design of architecture is called "One Phase Well". This novel innovation was initiated in 2019, where to date, the operator has drilled more than 30 wells without any incident. With the learning curve that has turned into industrialization steps. More and more shorter well duration is born with these two initiatives, MAXIDRILL and One Phase Well. Ultimately, with the spirit of these two initiatives for bringing down well duration in gain for much better well economics has successfully set a two record breaking performance in Mahakam: 1) Being the fastest On Bottom ROP and 2) Being the fastest well ever delivered in Mahakam and Indonesia which is under two days.
Manurung, Vinda Berlianta (Halliburton) | Himawan, Glen Ricky (Halliburton) | Warkhaida, Laila (Halliburton) | Zulharman, Ahmad (PT. Pertamina Hulu Kalimantan Timur) | Citajaya, Novrianto (PT. Pertamina Hulu Kalimantan Timur) | Laksono, Setiadi (PT. Pertamina Hulu Kalimantan Timur)
Abstract The Kutai Basin, has been under production for more than 40 years and many wells have been drilled to develop the area. This has resulted in reservoir-induced drilling problems, like kicks and lost circulation due to depletion, while some high-pressure zones still exist. This complexity makes pore-pressure and stress analysis difficult. To address this problem, a comprehensive reservoir-evaluation program was developed by adding formation pressure testing to the planned quad-combo logging-while-drilling (LWD) program. Pressure measurements in this development stage were planned to aid the operator's understanding of the field's current hydraulic communication pathways, to relate reservoir characterization to the geological model. Emphasis was on the insight of static reservoir pressures, which are important for confirming fluid contacts and fluid density gradients. Methods of formation pressure testing have evolved over many years. Through this paper's case study, recent LWD and wireline pressure-testing technology are elaborated in depth, in relation to two sequential wells drilled offshore in the Kutai Basin. LWD pressure-testing operations were conducted in well XX-5 in a dedicated run after completion of drilling the section. The wireline test was conducted in well XX-4 as an open-hole logging run, along with the acquisition of fluid analysis data. Both systems were successfully utilized in the 6-inch hole sections of the subject wells, in a depleted reservoir, with the pressure overbalance expected to reach around 3100 psi in the pre-job planning stage. The average mobility was low in both sets of pressure test results, as also align with the reservoir's current depletion state. Challenges related to tight tests and lost seals in this mature field were experienced with both systems. The drilling environment and the formation's exposure conditions may have presented varying challenges; nevertheless, the same relatable quality has been achieved with both types of testing (LWD and wireline). This paper describes in detail the planning, design, and performance of pressure testing using LWD and wireline in the Kutai Basin. Comparisons between results are displayed to highlight the current character of the subject offshore field. This study aims to enhance future drilling and logging operations, by reviewing solutions from formation pressure testing technologies and to add value to mature and depleted field planning. Technical Categories: Geotechnical, Geoscience & Geophysics; Drilling Technology
Kurniawan, Dian (Eni Indonesia) | Carrasquero, Gabriela (Eni SpA) | Daniel, Edo Richardo (Eni Indonesia) | Praja, Kurnia Wirya (Eni Indonesia) | Spelta, Elisa (Eni SpA) | Valdisturlo, Antonio (Eni SpA)
Abstract Implementing a proactive approach with comprehensive reservoir characterization, risks identification and mitigation are key elements that have to be deeply investigated before the project execution for achieving the optimum results in field development. A tremendous result on the seismic driven field development and synergy with a fast track development concept in Merakes green gas field has been achieved. In this paper, the conceptual and methodologies are described in the way of managing the subsurface risks and uncertainties during the planning and execution phase. A suitable example in Merakes field development which classified as "appraisal while developing", since the remaining risks still exist during development campaign, is presented. By having only two exploration wells with limited data, a robust upfront reservoir characterization and modeling were quite challenging to provide a reliable image of the subsurface condition. The enhancement on the way of constructing an integrated reservoir study prior to the field development is considered an essential requirement that has to be done before the project execution. A comprehensive approach that maximizes the integration of Geology, Geophysics and Reservoir Engineering disciplines and brings out the reservoir risk quantification has been considered as a basis and strategic driver for both subsurface quantitative description and de-risking of development wells locations. Focusing on the subsurface risk criticality, the compartmentalization, rock facies quality, gas-water contact depth and sand production were considered as the main critical aspects that could impact the final success. Preserving mitigation strategies and adapting development flexibility concept have been prepared to overcome such subsurface unexpected conditions. A description of the well placement strategy which widely open to be optimized during the drilling campaign was allowed and brought benefits in mitigating the compartmentalization risk. The readiness of an adequate and comprehensive data acquisition program including log data acquisition, coring and well testing in the development wells has been prepared. Moreover, a sidetrack contingency plan has been also considered for a key-well in case of worse than expected results. With know-how and experiences on the nearby field development, an extensive evaluation of water and sand production risks was derisked by selecting smart completion and sand control technologies. A holistic integration between subsurface, drilling, petroleum, facilities disciplines is considered of paramount importance in development projects. The awareness of the field's risks and uncertainties allows maximizing efforts in following up the drilling phase promptly adapting the data acquisition plan to the effective level of residual uncertainty and related development risk. Eventually the good match between the expected scenario and the actual well results allowed to cancel most of the costly data acquisition plans which contributed to a positive impact on the project cost and time-saving.
Poggi, Pamela (RINA Consulting S.p.A.) | Fiorini, Emilia (RINA Consulting S.p.A.) | Tonoli, Daniela (RINA Consulting S.p.A.) | Ioele, Francesca (RINA Consulting S.p.A.) | Parker, Eric John (RINA Consulting S.p.A.) | Musetti, Alberto (RINA Consulting S.p.A.) | Di Martino, Enrico (RINA Consulting S.p.A.) | Folcini, Fabio (ENI S.p.A.)
Abstract Objectives/Scope This paper presents an innovative web tool developed for the seismic monitoring of critical infrastructure. As an example, we describe an application for the ENI offshore facilities, Jangkrik and Merakes Fields Development, offshore Indonesia. Methods, Procedures, Process The system monitors reported seismic activity in a project area, and issues warnings when earthquakes detected may have directly or indirectly impacted facilities. Notifications allow the owner to optimize decisions regarding post-earthquake asset surveys and maintenance, avoiding the need for inspections in areas not significantly affected. A system of email alerts and a web based GIS platform provide the end-user with a tool to control its own assets. Results, Observations, Conclusions The purpose of the tool is to indirectly monitor earthquakes in an area and identify those which may have damaged the Oil and Gas facilities of interest. This identification requires accurate near real-time earthquake data such as date, time, location, magnitude, and focal depth. To this end, the system retrieves earthquake data from a qualified set of public seismic agencies. The system computes the expected values of shaking at the specific offshore facilities (platforms, subsea structures, pipelines, etc.). Calculations are based on sets of Ground Motion Prediction Equations (GMPEs) selected to match the seismotectonic environment. The expected values of seismic acceleration generated by an earthquake are compared with threshold values and a warning message is issued to the facilities supervisors when the ground acceleration exceeds design values. Threshold values related to secondary seismic effects (e.g., seismically induced landslides, debris flow) which could affect facilities integrity are also considered in the alert system. Threshold values are defined considering project seismic and geohazard documents, to summarize strong ground motion parameters that could potentially trigger damaging seismic geohazards, and project design documents to collect all data about seismic design of the assets. Monitoring intervals are defined based on the documentation screening. Several alarm levels are selected, based on the potential severity of earthquake effects. The more severe levels of ground motion, with high damage potential, can trigger recommendation for inspection. Novel/Additive Information Asset integrity and safety are key drivers in the offshore petroleum industry. Safety performance with respect to earthquakes is a fundamental issue in all seismic prone areas. The seismic alert system presented highlights, in near real time, earthquakes that are potentially critical for structures in an Oil and Gas field. This allows the owners to make quick decisions and plan necessary intervention regarding assets affected directly or indirectly by earthquakes. Exploiting the wide background of knowledge in engineering and geoscience and the modern availability of global earthquake data, the tool can provide useful assistance in managing asset integrity, regardless of the availability of local seismic networks or strong motion stations.
Pinartjojo, Djoko (Mubadala Petroleum) | Hutahaean, Edison Tamba Tua (Mubadala Petroleum) | McManus, Ian (Mubadala Petroleum) | Nerwan, Aphrizal S. I. N. (Baroid, Halliburton) | Hansen, Rudiny (Baroid, Halliburton)
Abstract Exploration drilling obviously requires a robust drilling fluid system to be a key factor in overcoming both the known and unexpected challenges of a structure that consists of reactive clay and lost circulation zones. Extra consideration has to be given to regulatory environmental requirements and complications resulting from regional politics. A High-Performance Water Based Mud (HPWBM) system was selected to address the aforementioned issues. The HPWBM was customized to respond to the subsurface conditions with the main requirement to provide maximum shale inhibition through a non-dispersed environment. Polyamine was utilized to stabilize all types of clay; an encapsulation polymer and a non-ionic polymer were included to prevent dispersion and to seal micro-fractures. A complete shale study was performed to determine the optimum concentration of the base fluid and each shale inhibitor. Then hydraulic behaviour of the mud was simulated with contractor proprietary software to understand the parameters for optimal hole cleaning as well as Equivalent Circulating Density (ECD) simulation. The HPWBM system successfully facilitated the execution of the exploration well and provided highly effective clay stabilization. No Non-Productive Time (NPT) was recorded as a result of reactive clay issues. The mud system also facilitated a good rate of penetration (ROP), formation stability, and lubricity. Waste cuttings transportation was not required. In addition, there is also no requirement for costly base oil including its associated transportation costs. The successful implementation of the HPWBM yielded an estimating saving of 25% compared to invert emulsion fluids, prior to considering costs associated with an expensive Liquid Mud Plant (LMP), environmental, and freight costs. Significant cost savings were achieved by eliminating the need for LMP rental, mobilization and demobilization. Another notable saving was realized from the reduced system maintenance of the HPWBM as less dilution was required compared to a regular Water Based Mud. Thinking outside of the box and embracing the departure from the default consideration of an invert system with a thorough risk assessment augmented value to wellbore construction. A smartly designed HPWBM system provided performance comparable to an invert emulsion system but with superior benefits with respect to environmental protection, simplified logistics and lower costs.