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.
Nguyen, T. T. T. (Australian School of Petroleum, The University of Adelaide) | Nguyen, L. A. T. (Australian School of Petroleum, The University of Adelaide) | Perdomo, G. E. M. (Australian School of Petroleum, The University of Adelaide)
Explored in 1964 and first oil production launched in late 1984, Mereenie oil and gas field is the largest onshore oil field in mainland Australia. Although the production within the Eastern region has been in decline, an appraisal and development drilling project is expected to extend the life of the field. Therefore, a good understanding of dynamic compartmentalization through validation of material balance modeling would address current production planning and monitoring focused in the current oil production formation, Pacoota 3. This study could be the foundation for future development of the western part of the field.
Over 30 years of production and an enhanced oil recovery scheme which involved periodic injection from abundant gas within the upper formation, Pacoota 1; the producing oil formation has yet had any in-depth study of a dynamic compartment within the production time scale. The main objective of this study is to provide an analytical framework for dynamic compartmentalization. This framework was developed to capture the complexity in completions strategy and in the injection period. In total, six compartments across the Eastern Pacoota 3 formation were successfully identified and confirmed through modeling. However, uncertainties in structure and limited data at the West have contributed to production simulation's shortcomings.
It was found that compartmentalization in Mereenie is a combination of variables; those are a natural baffle, fault sealing, injection rate, and drainage radius; while structural faults have a primary role in decreasing the permeability and mobility of oil, causing discontinuity throughout the formation.
In the Northern Territory, the Department of Mines and Energy (DME) is the agency responsible for regulating the exploration and production of oil and gas and the administration of petroleum tenures and petroleum pipelines onshore and in designated coastal waters up to 3 nautical miles seaward from the Territorial Sea Baseline of the Northern Territory. The DME’s role is to ensure that best-practice regulatory principles are applied for the sustainable and safe exploration and production of natural resources in the Northern Territory. In the Northern Territory, hydraulic fracturing has taken place since 1967, mainly as a process to enhance hydrocarbon production from conventional reservoirs with vertical wells. Since 2011, however, hydraulic fracturing has been carried out during exploration for unconventional hydrocarbons. Until now, developmental drilling has taken place only in producing fields in the Amadeus Basin.
This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 182404, “Unconventional-Resources Exploration and Development in the Northern Territory—Challenges From a Regulator’s Perspective,” by M. Rezazadeh, J. van Hattum, and D. Marozzi, Northern Territory Department of Mines and Energy, prepared for the 2016 SPE Asia Pacific Oil and Gas Conference and Exhibition, Perth, Australia, 25–27 October. The paper has not been peer reviewed.
The production of conventional onshore oil and gas in Australia’s Northern Territory began in 1983 from the Palm Valley Field (gas) in the Amadeus Basin. Until 2010, the industry relied on conventional oil and gas development technology, but, in recent years, the focus of the industry has shifted to unconventional-resource exploration. This paper outlines the key issues that must be addressed from a regulatory perspective in regard to the development of an onshore unconventional-gas industry in the Northern Territory.
In the Northern Territory, the Department of Mines and Energy (DME) is the agency responsible for regulating the exploration and production of oil and gas and the administration of petroleum tenures and petroleum pipelines onshore and in designated coastal waters up to 3 nautical miles seaward from the Territorial Sea Baseline of the Northern Territory. The DME’s role is to ensure that best-practice regulatory principles are applied for the sustainable and safe exploration and production of natural resources in the Northern Territory.
In the Northern Territory, hydraulic fracturing has taken place since 1967, mainly as a process to enhance hydrocarbon production from conventional reservoirs with vertical wells. Since 2011, however, hydraulic fracturing has been carried out during exploration for unconventional hydrocarbons. Until now, developmental drilling has taken place only in producing fields in the Amadeus Basin. In the McArthur, Bonaparte, South Georgina, and Pedirka Basins, exploration activities are ongoing.
Onshore Northern Territory oil production comes from the Mereenie and Surprise Fields. Until November 2015, onshore gas production in the Northern Territory came from the Mereenie and Palm Valley Fields. In December 2015, the Dingo Field began producing gas. In 2015, 3,703 MMscf of gas was produced from the three fields.
Current Northern Territory Onshore Petroleum Regulatory Framework
The Northern Territory Petroleum Act is the principal existing legislation regulating oil and gas exploration and production. The DME currently uses the Schedule of Onshore Petroleum Exploration and Production Requirements (referred to here as the Schedule) to regulate petroleum activities; this guideline is similar to that which Western Australia previously used. In 2015, Western Australia replaced the Schedule with its Petroleum Resource Management and Administration Regulations. The Schedule is used to provide requirements to regulate and audit all petroleum activities.
Rezazadeh, M. (Northern Territory Department of Mines and Energy) | Hattum, J. van (Northern Territory Department of Mines and Energy) | Marozzi, D. (Northern Territory Department of Mines and Energy)
The production of conventional onshore oil and gas in the Northern Territory began in 1983 from the Palm Valley gas field, Amadeus Basin South of Alice Springs. Up until 2010the industry relied on conventional oil and gas development technology albeit with substantial technological advances over time. In recent years the focus of the industry has shifted to unconventional resource exploration, particularly the highly prospective shale gas resources in the McArthur and Georgina Basins. Current estimates indicate that the Northern Territory has more than 200 trillion cubic feet of prospective unconventional natural gas resources in six basins. The technologies and techniques to explore and develop petroleum resources from deep shale are innovations on technologies and practices employed for exploration and development of conventional resources with revolutionary consequences, particularly in North America.
Rogers, Clint (Smith Bits a Schlumberger Company) | Jangani, Reza (Smith Bits a Schlumberger Company) | Spedale, Angelo (Smith Bits a Schlumberger Company) | Sadawarte, Sagar (Smith Bits a Schlumberger Company)
The Mereenie development project is targeting oil and evaluating natural gas reservoirs in the lightly drilled Amadeus Basin. In 2012, an operating company started searching for methods to improve rate of penetration (ROP) drilling the 8¾? vertical hole section through the difficult Stairway and Pacoota sandstone formations. The lithology consists of very abrasive and hard siltstone/sandstone with UCS up to over 30,000 psi. The hole section starts at 500 m and generally requires 700 m of total wellbore to reach KOP at 1200 m. The section has historically been drilled with PDC and Roller Cone bits with mud as the circulating medium. Both types of BHAs produced unacceptably slow ROP and required multiple trips to reach TD. The operator required a new approach.
To accomplish the objective, the operator wanted to switch from mud to underbalanced drilling using an air percussion BHA equipped with a hammer bit. However, an analysis using a well records database showed that only short (10–30m) shallow surface intervals had been drilled in Australia with percussion air hammers mostly in mining applications in the 1980–90's.
To increase the chance for early success, the operator wanted to import the latest air hammer tools and drilling techniques from North America. The provider suggested taking lessons learned from the Northeast USA where air hammer drilling plays a major role in developing oil and gas reserves in the region. The two applications are similar with regards to formation characteristics and the drilling team concluded the provider's downhole tool technology, service culture and experience/expertise would be integral to project success. In Q4 2013 the provider drilled the fastest and deepest percussion air hammer run in Australia's Oil and Gas history at 24 m/hr, 700% faster than the previous ROP achieved with PDC or Roller Cone.
The paper describes the reservoir management experiences of Kerisi field after seven years of production. Kerisi field is located in Block B of South Natuna Sea and comprises five separate reservoirs in three geological zones.
Forty seven percent of the reservoir hydrocarbons are located in the Upper Gabus Massive West (UGMW) reservoir; optimum production from this formation is expected to be reached by injecting gas at the gas cap. The source of injected gas is from all five Kerisi reservoirs and the nearby Hiu field. The liquid hydrocarbon production from UGMW and the production/injection of Kerisi – Hiu produced gas in this formation is of high importance to the future development stage of Kerisi – Hiu field.
The initial reservoir management strategy was to optimize oil value with injection while meeting gas sales requirements. Both gas sales commitments and injection targets were honored with high Kerisi – Hiu production and the strong performance from other gas fields.
With time, other gas fields became depleted faster than expected. Thus, it was decided to reduce gas injection rate in UGMW and produce more Kerisi and Hiu gas to increase gas sales volumes. The reduced of injection rates improved short term economic of the fields, but the effect to reservoir and long term economic benefit still needs evaluation.
This paper will (1) show the impact of varying injection rate at UGMW to the overall Kerisi – Hiu field future production, include oil, gas, condensate, and LPG, (2) discuss an updated – improved reservoir management strategy, and (3) present an economic evaluation of the updated reservoir management strategy for the Kerisi – Hiu fields.
The purpose of the paper is to share lessons learned in the evaluation of historical performance, data acquisition and monitoring, static and dynamic modeling, history matching, prediction of future performance, and the dynamics of reservoir management strategy which support future profitable opportunities.
Gas-aided gravity drainage is a common oil-recovery technique in anticline-shaped oil reservoirs. If the permeability is low and the reservoir is oil-wet, the remaining oil saturation can be quite high. The goal of this work is to mobilize a part of this oil by surfactant injection. An anionic-surfactant formulation was developed to alter wettability and lower interfacial tension (IFT) for a gasflooded, carbonate reservoir. Different coreflood strategies, including gas/water/surfactant/water (GWSW), gas/surfactant/gas (GSG), gas/surfactant/water (GSW), and gas/surfactant/water/gas (GSWG) floods, were investigated. GSG, GWSW, and GSWG corefloods conducted in limestone cores recovered an additional 40–50% of the original oil in place (OOIP) because of the injection of surfactant. GSW corefloods conducted in a vuggy dolomite recovered less: an approximately 20%-of-OOIP incremental recovery. Numerical simulation was used to match GSG and GSW corefloods and estimate multiphase-flow functions. A 2D conceptual simulation model using these functions was built for an anticline reservoir for gas and surfactant-solution injection. GSG flooding using wettability-altering surfactant exhibited high oil recovery at the field scale. IFT reduction, wettability alteration, and foam formation contributed to enhanced oil recovery (EOR).
Gas aided gravity drainage is a common oil recovery technique in anticline-shaped oil reservoirs. If the permeability is low and the reservoir is oil-wet, the remaining oil saturation can be quite high. The goal of this work is to mobilize a part of this oil by surfactant injection. Different coreflood strategies including Gas-Surfactant-Gas (GSG), Gas-Water-Surfactant-Water (GWSW), Gas-Surfactant-Water (GSW), and Gas-Surfactant-Water-Gas (GSWG) floods were investigated. GSG, GWSW and GSWG corefloods conducted in limestone cores recovered about 40-50% of the original oil in place (OOIP) due to the injection of surfactant. GSW corefloods conducted in a vuggy dolomite recovered less, about 20% OOIP incrementally. A 2D conceptual simulation model was built for an anticline reservoir for gas and surfactant solution injection. GSG flooding using wettability altering surfactant exhibited high oil recovery at the field-scale. IFT reduction, wettability alteration, and foam formation contributed to enhanced oil recovery.
This paper illustrates an innovative field-scale application of injecting condensate gas and recycling gas in Jake field, Sudan. This field has two production series, namely AG condensate gas pools and Bentiu oil pool from bottom to up, with the former 3520 ft. below the Bentiu reservoir and 1695 psi of initial reservoir pressure difference. Bentiu pool of Jake field is a medium crude oil (29 API) pool with strong aquifer support. Well productivity was 500 BOPD. Operator intended to inject high-pressure condensate gas into Bentiu pool to increase field output, whereas was confronted with following challenges: 1) injection of condensate gas in an easy-to-operate wellbore configuration; 2) optimization of injection parameters to achieve highest output; 3) suppress aquifer water breakthrough.
Field scale application had been optimized and implemented since 2010:1) High-pressure condensate gas had been injected into two updip crest Bentiu wells in the same well bore, following a huff-and-puff process, well output amounted 4,000 to 13,800 BOPD under natural flow; 2) 1/4 recycling gas volume from compressors was re-injected into 12 downdip wells at controllable pressure to avoid early water breakthrough; 3) The remaining recycling gas was utilized to gas-lift other five updip wells.
Oil producers were reduced from 19 to 7 comparing to original field development plan, while oil rate ascended from 22,000 to 30,000 BOPD, with watercut dropping to 7% from 15%, achieving a high offtake rate of 6%. Reservoir simulation indicated ultimate recovery factor is expected to be over 50% with such full-field gas injection.
Conclusions drawn from field scale injection of condensate gas and recycling gas were as follows:1) condensate gas injection in the same well bore was technically innovative and operationally robust; 2) recycled gas injection into downdip wells helped detain water breakthrough; 3) field scale application had evidenced outstanding success with high output and high offtake rate.