PETRONAS FLNG SATU (PFLNG1) is a floating liquefied natural gas facility producing 1.2 million tonnes per annum (mtpa) of LNG, on a facility that is 365m long, and 60m wide, making it among the largest offshore facility ever built. The PFLNG1 project is the first of its kind in the world and is the first deployment of PETRONASâ€™ Floating Liquefied Natural Gas (FLNG) technology, consolidating the traditional offshore to onshore LNG infrastructure into a single facility. This will see a giant floating facility capable of extracting, liquefying and storing LNG at sea, before it is exported to customers around the globe. The FLNG journey has come a long way since 2006, with many technological options explored to monetise and unlock the potential of small and stranded gas fields. Moving an LNG production to an offshore setting poses a demanding set of challenges â€“ as every element of a conventional LNG facility needs to fit into an area roughly one quarter the size in the open seas whilst maintaining safety and increased flexibility to LNG production and delivery. The keynote address describes the breakthrough features of PFLNG1 â€“ the worldâ€™s first floating LNG facility; and the pioneering innovation that it brings to the LNG industry.
Africa (Sub-Sahara) Drilling began on the Bamboo-1 well, located around 35 miles offshore Cameroon in the Ntem concession. The Bamboo prospect is a basin floor fan target within an Upper Cretaceous play. The well will be drilled to an estimated depth of 4200 m. Murphy Cameroon (50%) is the operator, with partner Sterling (50%). The Nene Marine 3 exploration well--located in the Marine XII block, which is around 17 km offshore Congo--encountered a wet gas and light oil accumulation in a presalt clastic sequence Eni (65%) operates the Marine XII block, with partners New Age (25%) and Société Nationale des Pétroles du Congo (10%). CNPC said PetroChina is now building a production facility capable of pumping 4 Bcm/yr.
Kamkong, Paphitchaya (PTTEP) | Karnjanamuntana, Thamaporn (PTTEP) | Prungkwanmuang, Weera (PTTEP) | Yingyuen, Jakkrich (PTTEP) | Oatwaree, Dejasarn (PTTEP) | Amornpiyapong, Nichakorn (PTTEP) | Khositchaisri, Patcharin (PTTEP) | Tivayanonda, Vartit (PTTEP) | Wongsuvapich, Dutkamon (PTTEP) | Tongsuk, Soraya (PTTEP)
Lunar field is a marginal gas field located in the Gulf of Thailand. A significant portion of reservoir sands is currently categorized as Additional Zones of Interest (AZI) which is not accounted in reserves. As for this kind of sand, the conventional petrophysical evaluation alone cannot certainly distinguish between hydrocarbon and water in the porous medium. The alternative method (dT LogR) for formation re-evaluation is therefore considered in attempt to reduce uncertainty in fluid classification and reveal hidden hydrocarbon potential from these AZIs.
There are 2 phases in verifying the validity of dT LogR method. Phase I: dT logR method (Ref.
Phase II: The production test data from perforated AZIs in phase I and the well correlation were then incorporated in dT LogR assisted log reinterpretation. Additional 13 gas-potential AZI candidates were identified for 2nd perforation test to prove the correctness of the recalibrated petrophysical model. The results showed success in model improvement of which its accuracy increased to 61% and no high water production was observed in any of them.
After using dT LogR method to assist petrophysical evaluation, a total of 469 metres of unperforated AZIs were reconsidered to be productive gas bearing formation. In other words, 22 BCF of gas reserves and 873 MSTB of condensate reserves from these upgraded AZIs were added. In addition, it is foreseen that the remaining AZIs of other platforms are to be further reevaluated and therefore improves the confidence in reserves booking and field development planning of Lunar Field.
In conclusion, the dT LogR method is a very useful tool for Lunar Field to significantly reduce uncertainty of fluid classification which in turn provides lots of benefits in gas field management adding immeasurable value to Lunar Field.
Without regulation pertaining to the use and discharge of surfactant for offshore enhanced oil recovery (EOR) process in Malaysia, we adopted the guidelines from OSPAR (Oslo Paris Convention) that governs the use and discharge of offshore chemicals in the North Sea Region. In OSPAR, the CHARM (Chemical Hazard Assessment and Risk Management) model is being used to assess the risk of offshore chemicals to the marine environment. CHARM prescribes the Predicted Environment Concentration:Predicted No-Effect Concentration (PEC:PNEC) approach which ratio determines the hazard quotient (HQ) in order to rank the chemical by colour banding. Our surfactant formulation achieved a HQ of 2.16 or Silver colour banding with the stipulation that the volume of the discharged produced water is twice the volume of chemical solution (squeeze) injected. Nevertheless, in providing more certainty and confidence for both operators and local regulators to allow for overboard discharge of our flow-back surfactant formulation, we conducted a comprehensive produced water dilution modelling called DREAM (Dose-related Risk and Effect Assessment Model). The model calculates the Environmental Impact Factor (EIF) of each component of the chemical in the discharged produced water. Similar to CHARM, the DREAM uses the PEC:PNEC approach, but its PEC input parameters include environmental influences such as weather profile, current, etc. and incorporates a slick model. Its output is a quantation of the risks to the receiving environment, called the Environmental Impact Factor (EIF); where EIF is more than 1, the impact to the environment is significant. We simulated the chemical fate of individual component of the formulation with the scenario whereby the produced water is not treated prior to discharge. The time-averaged EIFs were more than 1 across all weather windows, indicating the discharge of untreated chemical-containing produced water is likely to have a localized environmental impact. We used both CHARM and DREAM as decision support tools for effective management of operational discharges from offshore projects. Limitations and recommendations from DREAM simulation results in the context of our EOR application are discussed.
Koronful, Nour (Schlumberger) | Peters, Kenneth (Schlumberger) | Ali, Mohd Firdaus (Malaysia-Thailand Joint Authority) | Skulsangjuntr, Jirapha (Malaysia-Thailand Joint Authority) | Jiang, Long (Schlumberger) | Kleine, Adrian (Schlumberger) | Basu, Depnath (Schlumberger) | Bencomo, Jose (Schlumberger) | Hernandez, Jonathan (Schlumberger) | Brink, Gerhardus (Schlumberger)
High carbon dioxide in reservoirs limits successful exploration in many petroliferous basins, particularly in Southeast Asia. High reservoir CO2 in the offshore Malay Basin represents a significant exploration challenge. Some fields contain >80% CO2, which makes them unattractive targets for development. Various hypotheses on the origin of CO2 have been proposed but remain controversial. This paper shows that geochemistry and advanced petroleum system modeling help to resolve the origins of reservoir CO2 and allow quantitative estimates of CO2 in prospective reservoir targets prior to drilling. A novel workflow estimates the CO2 content in reservoirs based on knowledge of the chemical mechanisms for the origin of the CO2 and numerical simulation of geologic burial history. Heat flow, deposition of overburden rock, and the kinetics of specific reaction mechanisms control the timing of CO2 generation and the relative contributions of CO2 from different sources.
In this study, stable carbon isotope ratios of CO2 and methane (δ13CCO2 and δ13CCH4, ‰) were used to identify the source of the CO2 in Malay Basin gas samples. For example,
The Integrated Logistics Control Tower (ILCT) aims to enable vessel sharing across 15 Malaysia producing Petroleum Arrangement Contractors (PACs) to lower the logistics cost across upstream operations in Malaysia. Prior to this, each PAC operated their own vessels. Opportunities for synergy and sharing between PACs were rarely tapped resulting in fragmented demand and specification, which in overall leads to higher cost.
ILCT was triggered from a heuristic study in June 2016 and the study showed the potential of RM100 millions yearly cost saving from reduction of 10-20 vessels through fleet sharing across the producing PACs. A joint project management team was formed comprised of key logistics personnel from PETRONAS and PACs to execute ILCT. Operation simulations were conducted involving stakeholders from operations, Health, Safety and Environment (HSE), legal, finance, and procurements to identify current limitations, and the short, medium and long term solution in order to ensure such sharing will not compromise HSE and production performance.
The joint project management team has encountered multiple obstacles towards ILCT implementation such as vessel priority, marine HSE standardization, vessels technical specifications, joint coordination agreement, liabilities, cost allocation, accumulative contract value re-distribution, and governance matters. In overcoming the obstacles, the team has established ILCT Committee and ILCT Manual. The ILCT Committee comprises of PETRONAS and PACs members with the key roles to control the overall allocation of vessels, mediate any conflict, and improve ILCT performance. The ILCT Manual was jointly developed by PETRONAS and PACs to govern the implementation of ILCT and is regularly referred by PACs as guiding principle in operating vessels.
This national synergy resulted in 12 vessels reductions from 142 to 130 vessels that equivalent to RM100 millions of cost savings yearly. PETRONAS and PACs benefit from this synergy mainly through optimized traveling route, which results in lower Daily Charter Rate and fuel cost. It also supports PETRONAS’ agenda to nurture capabilities of local vessel owners to become regional vessel operators. The key success of ILCT lies on PETRONAS’ role as the regulator for Malaysia upstream industry, by orchestrating the cooperation across PACs in syncing the common alignment towards achieving the desired outcome of ILCT.
Malaysia's ILCT is the biggest integrated offshore marine transportation arrangement in the world, with 120 vessels involved in serving offshore transportation needs to 198 producing fields in East & West Malaysia.
MH 370 disappearances on 8 March 2014 while flying from Kuala Lumpur International Airport in Malaysia to Beijing Capital International Airport in China is a real testing ground for National Search and Rescue (SAR) in Malaysia environment. Based on this incident, Malaysia oil & gas started to measure the preparedness of industry in facing similar situation with helicopter used for offshore workers mobilisation. In ensuring higher percentage of probability for survivors' to be successfully rescued by including the optimization of'golden hours', seven factors were measured during the SAR Exercise: a.
As of early 2017, PETRONAS has approximately 40% of aging platforms & pipelines that aged more than 30 years. As a party to UNCLOS, Malaysia is legally bound to undertake Decommissioning of its asset. Internally, apart from PETRONAS’ existing Procedure and Guideline for Upstream Activities (PPGUA) that spell out the recommended decommissioning principles, PETRONAS has devised a new set of decommissioning review process, known as Abandonment Review (AR) to ensure PETRONAS get the optimum levels of assurance its require from the operator/contractor. The deliberation of every decom project application is according to the type of scope of works which covers wells plug & abandon, pipeline/floaters or integrated facilities.
Following the downturn in crude oil prices and major decline in oil production for some of its fields, PETRONAS had to further evaluate and finally decided to decommission one of its Small Field Risk Service Contract (SFRSC) field, specifically Kapal Field. Upon PETRONAS’ review & approval process completed, execution phase commenced with the least complicated scope of work, which consist of Plug & Abandon (P&A) of 4 wells, detachment of wellbay support structure (WSS), retrieval of mooring chains, anchors and flexible pipeline, and relocation of MOPU for warm stack/cold stack purposes. However, during Project Risk Assessment exercise, relocation of MOPU was identified as one of the critical path as it involves integrity of the existing MOP and as such posed a high risk to the whole cost and schedule of the project.
Since decommissioning of upstream facility consider as a niche subject in Malaysia, educating of various internal and external stakeholders was required in order to establish the key steps for the decommissioning execution. Liaising with related state agencies was done through Exclusive Economic Zone sitting, with Petroleum Safety Unit's (PSU) as the secretariat. PSU is one of the unit under Ministry of Domestic Trade, Cooperative and Consumerism (MDTCC) which responsible in coordinating the policies, licensing, regulations and activities related to the safety of petroleum, petrochemical and gas industry in Malaysia.
There were plenty of great experiences and important lessons that PETRONAS learned in this project which PETRONAS thought worth to share with the industry. PETRONAS believes that through each successive failure in what we're doing, our values were reshaped. Even though this decommissioning activity was a schedule-driven project, cost optimization always becomes the key condition for making project management decisions. Not to mention on PETRONAS’ aspirations to contributes to sustainable development by delivering economic, social and environmental benefits for all stakeholders, collaboration and Memorandum of Understanding (MOU) achieved between PETRONAS and Department of Fisheries (DoF) in Rig-to-Reef Program had opened up a new perspective on how PETRONAS’ decommissioning activities can contribute towards its corporate social responsibility (CSR) program.
Setiawan, A. S. (Carigali-PTTEPI Operating Company Sdn. Bhd.) | Simatupang, M. H. (Carigali-PTTEPI Operating Company Sdn. Bhd.) | Rachmadi, A. (Carigali-PTTEPI Operating Company Sdn. Bhd.) | Ratanavanich, S. (Carigali-PTTEPI Operating Company Sdn. Bhd.) | Pushiri, M. F. Mohd (Carigali-PTTEPI Operating Company Sdn. Bhd.)
In the event of high gas demand, infill well drilling is one of the best option to increase gas deliverability. Finding infill well opportunity in a brown field is a challenging task. Reservoir continuity, heterogeneity of the rock properties, pressure depletion and identifying undrained area are the major concern for infill wells candidate selection. A robust reservoir characterization and dynamic information are essential to provide some key understanding about the field.
The area of interest, Muda field, is located in the Block B-17 of Malaysia-Thailand Joint Development Area (MTJDA) which has been producing for more than 5 years. Integration of multidisciplinary data is very important to identify the potential hydrocarbon bypassed area. To start with, the geological model was built and constrained with seismic attributes after calibration to the well data. The high uncertainty of reservoir presence in the model was assessed by combining the sand distribution and porosity variation. Subsequently, history matching was performed to calibrate the model with actual production flow rates and reservoir pressure. A reasonably good history match was achieved and provides a certain degree of confidence in production forecast. As a result, it shows some potential undrained areas to be selected as the area of infill well candidate. The infill wells were drilled within 1 to 2 years later and the well results has demonstrated a successful delivery of infill well as expected both in encountered netpay and production.
This paper discusses a successful collaboration between multidisciplinary team members in the subsurface division to deliver infill well candidate by building a comprehensive reservoir model which integrate of all hard data from geological concept, seismic attribute, well and production. Five successful infill wells were drilled in accordance to this campaign, expected potential and volume are generally as expected with some surprises in some interval. The gas potential comes from these infills are very important to fulfil gas deliverability. It is foreseen that additional infill wells are expected and evaluated using the 3D reservoir model.
Fadjarijanto, A. (Carigali-PTTEPI Operating Company) | Rachmadi, A. (Carigali-PTTEPI Operating Company) | Setiawan, A. S. (Carigali-PTTEPI Operating Company) | Praptono, A. (Halliburton) | Suriyo, K. (Carigali-PTTEPI Operating Company) | Simatupang, M. H. (Carigali-PTTEPI Operating Company) | Pakpahan, O. (Carigali-PTTEPI Operating Company) | Costam, Y. R. (Carigali-PTTEPI Operating Company) | Zakaria, Z. U. (Carigali-PTTEPI Operating Company)
Fluid identification is a key component of formation evaluation and becomes one of the important parameters that underlie economic decisions in field development. The combination of high clay content in the thinly laminated shaly-sand reservoir, together with unknown water salinity, increases the complexity in the accurate quantification of hydrocarbon-bearing reservoirs. The inherent clay distribution affects the log data response of high gamma and low resistivity analyses. Those responses can lead to incorrect interpretations unless other log data responses are considered.
The low resolution of a common oil-based resistivity tool often fails to capture structurally complex, thinly laminated sand-shale formations. The low resistivity response results from high resistivity sand layers suppressed by low resistivity shale layers, which can result in misinterpretations of calculating high water saturation. Observations of other conventional well log data can provide early qualitative identification of the low contrast zone. Data from the Thomas-Stieber method, resistivity anisotropy, and high-resolution micro-imaging are available to reconstruct conventional log data to provide an enhanced vertical resolution for final interpretations.
A field study was performed in the North Malay basin. Geologically, the field has three-way dip closure, bounded by a west-dipping fault to the west. The early evaluation of the DS2-B layer was interpreted as shale zones following a high gamma and low resistivity reading. Further observation of the density, neutron, and shear sonic trend do not provide the same shale indication. The decision was made to run a formation tester tool and to investigate any possible hydrocarbon indication. Real-time fluid identification and sampling proved the DS2-B layer to be gas-bearing and indicated that the conventional petrophysics-calculated water saturation was too high. Three petrophysics re-evaluation approaches were performed to define the reservoir challenges, including deterministic, Rv/Rh methods, and high-resolution data approach to obtain a better definition. All available data were used on the methodologies, based on the data required for each method, particularly the use of high-resolution imaging and core data for conventional logs to define the high-resolution of porosity, clay volume, and water saturation. As a result of these analyses, the DS2-B layer was proven to be a pay zone with a lower water saturation, which correlated with the formation sampling and core analysis results. The methodology has a proven capability to identify low contrast zones and can provide better interpretation in the field study through providing more a precise and accurate net-to-gross calculation.
The correlation and calibration of the conventional well log data to high vertical resolution image log, core data, and fluid sampling have provided a means of better visualizing and understanding the features of thinly bedded reservoirs in the field study. All methods were performed to calculate the final fluid saturation in highly laminated reservoirs. The new interpretation has proved a significant contribution to the NM field economic value.