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Since the industrial revolution, the oil and gas industry has played an important role in the economic transformation of the world, fueling the need for heat, light and mobility of the world’s population. Today, the oil and gas industry has the opportunity to redefine its boundaries through digitalisation, after a period of falling crude prices disrupted exploration and production activities, and ineffective mature field development challenges that are currently facing most oil and gas companies in Indonesia. The recent downturn in the oil and gas industry has led to massive layoffs. Digital industrial revolution is slowly changing how upstream businesses operate. Increasing public awareness of climate change has fuelled the urgency to shift to cleaner alternative energy.
Cai, Xiao (CNPC Engineering Technology R&D Company Limited) | Guo, Qingfeng (CNPC Engineering Technology R&D Company Limited) | Fu, Chunkai (University of Louisiana at Lafayette) | Jiang, Hongwei (CNPC Engineering Technology R&D Company Limited) | Liang, Lei (CNPC Engineering Technology R&D Company Limited)
Due to the special working environment, offshore drilling operation faces multiple challenges such as narrow pressure margin, difficulty in detecting down hole conditions and high operational risk. A new managed pressure drilling equipment is developed and named as pressure control drilling system-I (PCDS-I), which integrates the techniques of constant bottomhole pressure and microflux control and it is capable of performing the underbalanced, near-balanced and overbalanced MPD drilling as required. This new-type managed pressure drilling equipment is applied in several offshore wells to perform near-balanced managed pressure drilling operations with great success.
Before utilizations, real-time hydraulic calculations are conducted based on the field data and back pressures are designed for reducing the density of drilling fluid. In the field applications, the PCDS-I precisely keeps the bottomhole pressure constant and minimizes the pressure fluctuations, creating a near-balanced drilling condition. In addition to the real-time bottomhole pressure measured by pressure while drilling (PWD) equipment, the pumping rate and returning rate of drilling fluid are monitored by the PCDS-I. The cumulative pumping and returning volumes of drilling fluid and their difference are calculated by a program and compared with the volumes of drilling tools, providing a new way to detect the overflow and lost circulation in the tripping operations. Data of other operators are monitored and analyzed, such as logging data, providing reference for detecting the downhole condition and determining the back pressure.
Multiple drilling processes are successfully completed without any issue occurs with the assistance of this new managed pressure drilling equipment, including drilling, ma king connections, tripping, snubbing and circulating, etc. Cooperated with the PCDS-I, the density of drilling fluid dramatically reduces, which minimizes the possibility of formation damage and benefits the identification of pay zones. Simultaneous monitoring of pressure and flow rate enables the PCDS-I to accurately detect and deal with several overflow incidents in time. Near-balanced drilling condition is created by the PCDS-I which significantly increases the rate of penetration while preventing the pipe sticking and wellbore collapse, contributing the improvement of operation efficiency. A well using the PCDS-I even set a single bit footage record of 312.88 m and daily footage record of 163 m. No drilling issue is reported in the applications of the PCDS-I.
Successful applications of the PCDS-I demonstrates its technical advantages in solving the issues of offshore drilling. Utilization of this new-type managed pressure drilling equipment dramatically minimizes the potential of well control and ensures the down-hole safety, controls the formation damage and assists pay zone identification, enhances the drilling performance and reduces the non-production time, improves the drilling efficiency and economic benefits.
Complex hydrocarbon distributions where reservoirs are filled by oil and gas phases with different densities and genetic types interfingering within a basin are a common phenomenon in Southeast Asia and are often attributed to vertical migration. Attempts to understanding the controlling factors of vertical hydrocarbon migration by modeling the hydrocarbon charging and entrapment history from two Cenozoic basins in Southeast Asia—West Java and the Madura Platform—are discussed.
A modified invasion percolation algorithm was used to simulate the secondary migration models, which follows the principle that migration occurs in a state of capillary equilibrium in a flow regime dominated by buoyancy and capillary forces. Three-dimensional (3D) seismic data were used as the base grid for migration simulation to capture the effect of both structure and facies variations on fluid flow.
Two models, one from the West Java Basin (fault-bounded structure) and the East Java Basin (nonfault-bounded structure), are presented. For both cases, interfingering between oil and gas occurred, with most oils trapped within the lower formations, a mixture of oil and gas dominates the middle formations, and mostly gas in the upper formation. These vertical arrangements are possible because of the relatively weak formational seals within the basin. For vertically distributed reservoirs, oil is often trapped within the lower interval, and gas is trapped at the upper interval. For a basin dominated by a vertical migration regime, the potential risk for hydrocarbon lateral travel far away from the kitchen is high, thus increasing the potential risk of prospectivity away from the kitchen. Understanding factors that help control vertical migration also help geologists better understand hydrocarbon distributions within the basins.
Case studies during which modeling helped determine the factors that influenced vertical hydrocarbon migration and the resulting potential phase distribution prospectivity risks in the studied basins are discussed.
The PDF file of this paper is in Russian.
Present-day concept of the structure of the Pre-Jurassic basement of the Western Siberia is presented. The geological model of the Western Siberia as geosynclinals model is generally received. The geodynamic approach to this problem has been developing in the last 50 years. This approach based on the theory of the plate tectonics allows to estimate petroleum potential of the pre-Jurassic complex newly. There is opinion the basement of the Western Siberia plate is a continuation of the Central Asian Foldbelt. The contemporary analogue of the Central Asian folded belt is the south-eastern margin of Asia, represented by the junction area of the Indo-Australian and Pacific tectonic plates. Hydrocarbon accumulations various in size including Vietnam oilfields track this area. At present, the pre-Jurassic basement of the Western Siberia (its structure and composition) is insufficiently studied. Analysis of literary data by composition of Pre-Jurassic rocks and the location of oil and gas areas of the globe, the distribution of gas hydrate accumulations and hydrocarbon manifestations in the World ocean in the concept of the plate-tectonic model showed that the pre-Jurassic complex of the Western Siberia is represented by rocks and geodynamic conditions for their formation favorable for the formation of reservoirs and hydrocarbon accumulations. The detailed researches of basement rocks on the developed oilfields carried out by authors earlier showed the rocks was formed in various geodynamic conditions. However, the complex structure of the pre-Jurassic basement – its block structure, intensive disjunctive tectonics and non-uniform development of secondary processes with different directions in relation to the formation of the void space – make the search for hydrocarbon deposits very difficult in it. Found deposits of oil, gas condensate and gas in the Pre-Jurassic basement indicate its prospects for hydrocarbon raw materials
Изложены современные представления о строении доюрского основания Западной Сибири. Традиционно геологическая модель Западной Сибири понимается с позиции геосинклинальной концепции эволюции земной коры. В последние 50 лет развивается геодинамический подход к решению данного вопроса, основанныйна плейт-тектонической концепции, который позволяет по-новому оценить перспективы доюрского комплекса. Данный подход предполагает, что основание Западной Сибири является продолжением Центрально-Азиатского складчатого пояса, геодинамическим аналогом которого в настоящее время считается юго-восточная Азия – зона взаимодействия Тихоокеанской и Индо-Австралийской тектонических плит, которая трассируется залежами углеводородов разного масштаба, в том числе известными месторождениями Вьетнама. В настоящее время доюрское основание Западной Сибири (структурное строение, вещественный состав) недостаточно изучено. Анализ имеющихся литературных данных о вещественном составе пород доюрского комплекса Западной Сибири, размещении нефтегазоносных регионов Земного шара, распределение скоплений газогидратов и углеводородных проявлений в Мировом океане в концепции плейт-тектонической модели показал, что доюрский комплекс представлен породами и геодинамическими обстановками их формирования благоприятными для образования коллекторов и скоплений углеводородов. Проведенные ранее авторами детальные исследования пород-коллекторов доюрского основания на разрабатываемых месторождениях показали, что породы формировались в разных геодинамических условиях. Ввиду сложного строения доюрского основания – его блокового строения, интенсивной дизъюнктивной тектоники и неравномерного развития вторичных процессов, разной направленности в отношении образования пустотного пространства – поиск залежей углеводородов в нем сильно затруднен. Выявленные залежи нефти, газоконденсата и газа в доюрском основании свидетельствуют о его перспективности для поисков залежей углеводородов.
Nugroho, Wisnu Agus (Pertamina Hulu Energi ONWJ) | Panaiputra, Harris Grenaldi (Pertamina Hulu Energi) | Kusuma, Dian Nurlita (Pertamina Hulu Energi) | Wirawan, Alvin (Pertamina Hulu Energi ONWJ) | Hartawan, Iman Budi (Pertamina Hulu Energi) | Hapsari, Ratna (Pertamina Hulu Energi)
Currently Indonesia apply new gross split production sharing contracts for the oil & gas industry. Regulation of the Minister of Energy and Mineral Resources Number 8 of 2017 on Gross Split Production Sharing Contracts sets out a new economic structure for production sharing contracts (PSC) based on dividing gross production between the state and PSC Contractors, without a mechanism for the PSC Contractor to recover operating costs. For mature field, high operating cost regarding low production, high maintenance, and integrity issues are challenging for this new regulation. To optimize operating cost with robust and prudent planning is one of the key of success in this era. Pertamina Hulu Energi Offshore North West Java (PHE ONWJ) has started gross split scheme since January 2017 which start a new era of production sharing contracts.
With the start of gross split scheme, prioritization of production is the main objective, to gain maximum productivity in terms of operating and lifting cost. The methodology to optimize operating cost is by prioritizing productive remote well platform, Normally Unmanned Installation (NUI), by ranking of potential development and its production volume. The non-potential and non-productive NUI then be assessed to be shut off or run to fail. The assessment conducted using technical and economic approach to obtain optimized result. For non-potential and productive NUI, assessment to gain more production with minimum cost is conducted. Then, development could be focused on potential and productive NUI.
Foxtrot, one of flow station in PHE ONWJ working area, has eight active NUIs that are FA, FK, FG, FFB, FNB, FWB, HZEA, and HZEB. By conducting ranking of potential development and its production volume, company could focus on five Foxtrot NUIs for development (FK, FG, FFB, FWB & HZEA), two NUIs for optimization (FNB & FA), and one NUI that potential to be shut-off, HZEB. This action on the non-potential and non-productive NUI shut off could yet decrease operating cost by IDR 8.8 Billion/ year, eliminate potential personal hazard, and reduce system's backpressure due to its low API crude oil. Oil and Gas Company that operates old facilities in mature field could apply this approach to maintain their production by focusing on beneficial asset yet decrease operating cost.
Firdaus, Iman (Saka Indonesia Pangkah Limited) | Gultom, Luhut (Saka Indonesia Pangkah Limited) | Sadat, Anwar (Saka Indonesia Pangkah Limited) | Negara, I Made A. Sutha (Saka Indonesia Pangkah Limited) | Yusuf, Hotma (Saka Indonesia Pangkah Limited) | Harfoushian, Jack (Schlumberger) | Juandi, Dedi (Schlumberger) | Adeyosfi, Merza (Schlumberger) | Sudarwoto, Rinaldi (Schlumberger) | Wibowo, Febrian (Schlumberger) | Herianto, Bambang (Schlumberger) | Hartanto, Rudi (Schlumberger)
Saka Indonesia's primary objective of drilling an appraisal well offshore North-East Java was to accurately assess productivity of the three main reservoirs discovered by the exploration well drilled in the Pangkah Block. This paper details the integration of advanced formation evaluation procedures and interpretation of image logs with novel formation testing methods, which were used to plan and optimise drill stem tests (DST) conducted across the three reservoirs.
Deployed on wireline, formation evaluation and electrical borehole image logs were acquired in open hole of the exploration well. Nuclear magnetic resonance (NMR) and image logs were processed simultaneously in near real time to facilitate the planning of the subsequent formation pressure testing and fluid sampling program. Using the recently introduced advanced formation testing technology, reservoir deliverability was accurately established, in addition to characterising fluids insitu and obtaining reservoir fluid samples.
Interpreted results of data acquired on wireline from different logging runs were integrated and consequently used to optimise the well testing program across the intercepted heterogeneous and low permeability limestone reservoirs. In addition to determining porosities, free fluid volumes and the range of permeabilities, Drill Stem Test (DST) zones were confidently defined using the free water levels ascertained by constructed vertical pressure profiles. As a result, DST measurements matched the permeability and productivity estimations across the three pay zones.
The integrated approach of formation evaluation, textural analysis and permeability and productivity measurements enabled the evaluation of three complex limestone reservoirs discovered in this field, which included secondary porosities and interconnected vugs. These results were ultimately verified and confirmed by the well tests conducted across the three reservoirs.
Wibowo, Icuk Dwi (Pertamina Hulu Energi – Offshore North West Java) | Prawesti, Annisa (Pertamina Hulu Energi – Offshore North West Java) | Sobani, Sobani (Pertamina Hulu Energi – Offshore North West Java) | Saputra, Lulus Ilmiawan (Pertamina Hulu Energi – Offshore North West Java) | Maulana, Taufik (Pertamina Hulu Energi – Offshore North West Java) | Luciawaty, Mery (Pertamina)
Alengka Field has been producing for more than thirty years. Like the vast majority of oil and gas field in the world, Alengka field production is on decline. Alengka Field pay reservoirs consist of more than fifteen zones which are separated in three structures. Latest infill and workover activities reveal that the major productive zones are showing watered-out and depleted reservoir pressure. The last remaining potential reservoir is a low resistivity pay zone which not fully developed yet, called as Rama and Shinta zones.
These low resistivity pay reservoirs are member of Main Formation which deposited in shallow marine depositional environment. It is characterized by 30-60 feet of pay thickness, with resistivity ranging from 1.4 ohmm up to 2.2 ohmm, with shale background resistivity up to 1.2 ohmm. It has an effective porosity up to 22% and permeability up to 10 md. The hydrocarbon existence is emphasized by the ratio of total gas reading to the background gas which more than 10 times; with peak gas up to 830 unit and poor to fair oil shows.
It is a huge contest for the offshore company to seek mature field redevelopment strategy with aging facilities to extend the economic producing life by using cost-effective and low-risk technologies. Commingle Rama and Shinta zones have demonstrated to be productive reservoirs by hydraulic fracturing. Each well can contribute 300 up to 700 BOPD of initial rate by utilizing gas lift and add 0.5 up to 0.7 MMBO of reserves. Naturally, hydraulic fracturing reservoir has rapid decline in the beginning production period which will be followed by plateau decline. The optimum fracturing parameter and gas lift performance which is combined with low angle trajectory well is identified as the essential key to improve production rate and to add maximum reserves.
Low resistivity pay zones has become the new reservoir backbone for redevelopment of Alengka field with total of 14 wells that will be drilled and 4 workover wells from 5 existing platforms that will be executed within next 3 years to add more than 7 MMBO of reserves. It will sustain Alengka field production rate more than 4000 BOPD. The recent activities consist of one infill drilling and one workover has excellent result with more than 800 BOPD in total. The successful of this campaign could open the opportunity to develop field further to the eastern part of the Alengka Field by adding new platforms and wells with total potential reserves is more than 10 MMBO. The paper will discuss about the low resistivity pay zone, production approach, recent drilling-workover results, redevelopment strategy in mature field and its challenges.
A collaborative effort between subsurface, operation and commercial team has successfully escalated the value of idle marginal offshore brown field in south east Sumatera, Indonesia. Over the past several years Lidya field was idle due to wellbore and facility problem, big investment value are needed to reactivate Lidya field and it creates hesitation in management decision, also there is a security issue to be considered. This paper describes the methodology applied in evaluating all aspects considered to mitigate the investment risk, escalating economical value and to ensure all parameters perform as expected.
The evaluation method divided into three major parts, the first part starts from subsurface study that involving geophysical processing, geologist re-interpretation, and reservoir engineering analysis, one of the most important factors to be taken into account is the necessity of a good understanding of the reservoir in order to increase the possibility of success. The second part is operation evaluation, it captures production engineering analysis from well integrity assessment to artificial lift selection, facilities observation from pipeline assessment to platform refurbishment option and also designing new security system to prevent cable thievery. The third part is the most crucial part to justify the value of Lidya marginal field reactivation project, challenges in this part also interesting, because production sharing contract term has changed from Cost Recovery to Gross Split mechanism, several cases was observed by commercial team to find the very best case with the least risk that might occur and affect the investment.
As a result, the value of Lidya idle marginal field was escalated. It can be quantifed from oil rate that increase from 150 BOPD for the last five years before it went idle to 700 BOPD for full cycle project. Economic side also appealing, observation multiple cases led to optimum case that can give total contractor net cash flow at almost 19Million USD in new fiscal term Gross Split mechanism, this number is 4 times higher than Cost Recovery mechanism for contractor profitability.
Developing marginal offshore mature asset is a risky business, especially considering high volatility in oil prices. Collaboration and technology are vital to escalating the value and achieving higher recovery factors. Application of the multidisciplinary methods was considered as an appropriate way to approach and manage a complex marginal mature field redevelopment.
Akbar, Muhammad Nur Ali (University of Miskolc) | Salam, Agihtias (China University of Petroleum, Beijing) | Awab, Malik (Institut Teknologi dan Sains Bandung) | Prakoso, Suryo (University of Trisakti)
This paper presents new interrelationships of elastic properties of the porous rock to petrophysical parameters in order to enhance better understanding on how compressional and shear waves velocities, young modulus, bulk modulus, lame’s coefficients, and Poisson’s ratio correlate with permeability, porosity, petrophysical geometric details of the pore system, and microscopic geological features.
This study employs 215 sandstone core-plugs from North West Java Basin. The approach used utilizes the Kozeny-Carman equation with Re-arrangement made on this equation leads to rock typing based on pore structure similarity, similar in pore shape factor and tortuosity. By plotting pore geometry against pore structure variable, it shows that P- and S-wave velocities, young modulus, bulk modulus, Poisson’s ratio, and lame’s coefficients data can be clearly grouped based on rock type and have strong correlations with permeability, pore geometry, and pore structure parameters. This grouping method enables to investigate the main influential factors that systematically control rock elastic properties. The interrelationships of each parameter of P-wave and S-wave velocities, young modulus, bulk modulus, Poisson’s ratio, and lame’s coefficients versus pore geometry and pore structure were constructed. The critical finding is that each relation among the rock groups of each elastic property is clearly separated. Each rock type has a similar pattern in that P-wave and S-wave velocities increase with pore geometry and pore structure variables. These velocities tend to be high with an increase in Kozeny constant. However, for a given porosity for all the groups, these velocities increase remarkably with a decrease in Kozeny constant. In other word, velocities increase with either an increase in the complexity of pore systems or, at the same pore complexity, a decrease in specific internal surface area. In addition, young modulus, bulk modulus, and lame’s coefficients also increase with pore geometry and pore structure in each rock type.
As a novelty, this study helps to characterize the elastic properties based on porosity and permeability data in the form of pore geometry and pore structure. Furthermore, this work can help us to predict some elastic properties at in-situ condition as long as we have the porosity and permeability values interval.
Ginanjar, Aji Rahmat (PT. Pertamina EP) | Anggraeni, Esti (PT. Pertamina EP) | Subhan, Muhammad (PT. Pertamina EP) | Aditya, Adzuhri (PT. Pertamina EP) | Suhartanto, Ibnu (PT. Pertamina EP) | Wibowo, Wisnu (PT. Pertamina EP) | Hasani, Nurul (PT. Pertamina EP)
Onshore Northwest Java Basin (NWJB) is one of the proven hydrocarbon basin in Indonesia. Conventional Play for this basin are limited to deep reservoir target such as Parigi, Cibulakan, BRF, TAF and Jatibarang Formation. This lead to high cost for drilling. This Paper present new insight on Shallow target with less than 1000 m and proven as good reservoir.
Previous study show that Cisubuh Formation is not a reservoir in many regional stratigraphy chart; it is a regional seal in onshore NWJB. This Formation contain only shale with intercalated sandstone in previous study. The method in this study is detail subsurface mapping of Cisubuh Formation in onshore NWJB including Seismic inversion analysis from seismic data to detect hydrocarbon anomaly, combine with lithological description from cutting and integrated with outcrop data and geochemistry data.
Sequence stratigraphy and lithological description is use to make more accurate stratigraphic colomn of Cisubuh Formation. The result show there are Carbonat buildup in Cisubuh Formation, transgressive sand that have good reservoir property and conglomerate. Moreover, from outcrop study it show that Total Organic Carbon from 17 sample have a value 0,27 - 4,43%, it means Cisubuh Formation have a low-very good candidate as a source rock. From Pirolysis Rock Eval Analysis show that this formation have Tmax 331-557° C with Hydrogen Index 3-338 H/g. That means that the sample from this Formation is mature-over mature and from Hydrocarbon index this formation categorized as gas prone and oil prone.
Drilling of KYM-01 well proving that Cisubuh formation is a good reservoir, it produce two MMSCF gas from Cisubuh interval. Optimizing this sudy will help for future development on many oil fields on onshore NWJB, shifting the paradigm from depth reservoir target