This course discusses the fundamental sand control considerations involved in completing a well and introduces the various sand control techniques commonly used across the industry, including standalone screens, gravel packs, high rate water packs and frac-packs. It requires only a basic understanding of oilfield operations and is intended for drilling, completion and production personnel with some sand control experience who are looking to gain a better understanding of each technique’s advantages, limitations and application window for use in their upcoming completions.
Numerous carbonate reservoir discoveries were made in Indonesia (
The process involves multiple cycles—from formation evaluation (e.g., geomechanics analysis, design of an effective fracturing method, and production forecasting) through the economic impact to the operator. During the early phase of this integrated study, the uncertainties of all static and dynamic parameters (i.e., geological complexity, rock physics, and stress profile) were considered for fracturing design. Production performances from multiple fracturing stimulation scenarios were then modeled and compared to select the plan that optimizes production for the Berai Formation.
Results demonstrated an effective multidiscipline approach toward a comprehensive strategy to meet the ultimate objective in optimizing production. This project leveraged formation evaluation and fracturing design to deliver integrated solutions from exploration to accurate production forecast. The well stimulations were performed by carefully selecting fluid characteristics based on geological-petrophysical properties, pressure, and stress profiles within the area. Results yielded excellent production gains—for the best case, up to 50% with an average of 40% in comparison with initial production by using an acid that provides optimum fracture geometry and permeability.
This opportunity demonstrated the importance of understanding formation behavior and the parameters that aid the selection of an appropriate fracturing design for a low porosity/permeability carbonate reservoir.
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) Oil was discovered at the Ekales-1 wildcat well located in northern Kenya. The well has a potential net oil pay in the Auwerwer and Upper Lokone sandstone reservoirs of between 197 ft and 322 ft. Tullow (50%) is the operator in partnership with Africa Oil (50%). Drillstem tests on the Pweza-3 well offshore Tanzania flowed at a maximum rate of 67 MMscf/D of gas. The tests confirmed the excellent properties of the Tertiary-section reservoir. BG Group (60%) is the operator in partnership with Ophir Energy (40%). Asia Pacific China National Offshore Oil Corporation issued a tender to invite foreign firms to bid for oil and gas blocks in the east and south China Sea. Twenty-five offshore blocks will be offered, including 17 in the South China Sea, three in the East China Sea, and five in the Yellow and Bohai seas.
Africa (Sub-Sahara) A drillstem test was performed on the Zafarani-2 well--located about 80 km offshore southern Tanzania. Two separate intervals were tested, and the well flowed at a maximum of 66 MMscf/D of gas. Statoil (65%) is the operator, on behalf of Tanzania Petroleum Development Corporation, with partner ExxonMobil Exploration and Production Tanzania (35%). The FA-1 well--located in 600 m of water in the Foum Assaka license area offshore Morocco--was spudded. The well targets Eagle prospect Lower Cretaceous resources. Target depth is 4000 m. Kosmos Energy (29.9%) is the operator, with partners BP (26.4%),
The Sanga-Sanga PSC fields are located onshore Mahakam delta, East Kalimantan, Indonesia. Since the 1970s, they have produced over 80% of originally estimated gas in place with the remaining gas locked up in low permeability sands. A prize of at least 0.75 Tcf would be achievable, if these sub milli-Darcy resources could be developed. However, previous attempts at hydraulic fracturing, over three decades, have been spectacularly ineffective and rarely enjoyed any improvement or uplift at all.
During late 2006, a detailed review of the regional stress-state and prior unsuccessful frac operations was performed. This review unearthed significant evidence of a reverse stress-ordering in the deep low permeability sands, resulting in horizontal fractures being created. While this provided some logic behind the widespread failure rate, it did not in itself offer a direct solution. However, there was also sufficient evidence from previous frac history, to indicate that the solution may lie with a pore-pressure reduction. A pilot program, with meticulous candidate selection was planned to investigate this.
Further investigation determined the presence of a strong poro-elastic relationship and it was assessed that when combined with longevity of production (30 years), that the stress-state would be substantially affected. During 2008, a suite of well candidates were carefully selected with a range of reduced pore- pressures, aligned with the poro-elastic understanding, hydraulic frac treatments were performed and the wells flowed and produced for two years to confirm productivity. The subsequent production behaviour, confirmed a very positive response and the treated wells netted substantial gas/condensate sales. Production behaviour confirmed the poro-elastic relationships and a set of absolute guidelines on candidate selection and fracture execution were created. Subsequent operations that have adhered to these strict guidelines have been extremely successful. The ability of the new approach to reverse a 30- year trend of hydraulic fracturing failure will now lead to the development of the remaining resource within the fields. An extensive treatment campaign will now be possible to perform with between 50 - 100 candidates well opportunities likely to be available in the field.
A careful assessment of the regional stress-state indicated a reverse ordering of the principal stresses as being the root cause of the poor hydraulic fracturing behaviour. However, careful consideration of the rock mechanics and a coherent pilot programme demonstrated the ability, under effective depletion conditions, to place economic and successful hydraulic fracturing treatments.
Indonesia has began the unconventional operation since 2003, VICO and MEDCO as a pioneer in Coal Bed Methane (CBM) working Area. Since 2005, two (2) big company has begun study and survey seismic operation for Kutai Basin (VICO Indonesia) and South Sumatera Basin (MEDCO E&P). The results are neededmore survey seismic and massive drilling well, which the needs of study and evaluation to get more comprehensive calculation on gas methane reserves and the strategy of Exploration and Development phase on each basin
The success ratio by numbers of drilling operation of CBM wells in Kutai Basin and Sumatera Basin were not significantly good as early prediction. This condition made some CBM contractors working areas has to leave and do farm out from the area. Nowadays, by counting the total of Unconventional Working Area in Indonesia, the active operation area are around 40 places in Sumatera and Kalimantan.
The slow down activities of CBM operation are caused by the minimum number of success ratio to discovery and to produce Methane Gas; challenge for the contractors to fullfill the commitment which where list stated on Production Sharing Contract (PSC). Other obstacles are the permits, where contractors get more difficulties to do all the activities, such as land acquisition permit (IPPKH if needed), environment permit (UKL/UPL), Rig License permit, procurement process and else.
Nowadays, Government of Indonesia has given more simplication for contractors in Regulatory area, Procurement Policy and Operating Procedure Guideline to do CBM activitiesin Indonesia.
With several breakthroughs have been taken by the Government of Indonesia, in future prospect CBM activities will be expected back to normal with more efficient by collaboration of government and contractor for technical and technology in exploration and drilling activities. By the results of Methane Gas discovery increased the Total Reserves and Energy Resilience of Gas in Indonesia.
Aslam, B. M. (Institut Teknologi Bandung) | Ulitha, D. (Institut Teknologi Bandung) | Swadesi, B. (Institut Teknologi Bandung) | Fauzi, I. (Institut Teknologi Bandung) | Marhaendrajana, T. (Institut Teknologi Bandung) | Purba, F. I. (Pertamina EP) | Wardhana, A. I. (Pertamina EP) | Buhari, A. (Pertamina EP) | Hakim, R. (Pertamina EP) | Hasibuan, R. (Pertamina EP)
Tanjung Field is a brown field which pressure has already depleted and been supported by waterflooding for over a decade. To improve production, surfactant injection, is being studied to be employed in the field. The main objective of this study is to identify parameters that affect oil production increase. History match of the pilot test was carried out to improve the reliability of the reservoir model, hence improving the prediction result of surfactant injection forecast.
History match of the pilot test has been carried out using CMG STARS commercial simulator by considering mechanism inferred from laboratory evaluation such as wettability alteration, surfactant retention, interfacial tension reduction and improvement of mobility control due to lower oil-surfactant emulsion viscosity. These parameters are initially perceived from laboratory result, upscaling and adjustment is applied to field model to further on do sensitivity study. Sensitivity analysis of every parameter is provided to better understand the effect of each mechanism that contributes to the oil incremental result.
Stratigraphically, Tanjung Structure has 7 productive zones: Zone A, B, C, D, E, F and P. Reservoir Zone A has total estimated reserve of 193,732 MMSTB, with recovery factor of 16.3%. The zone consists of conglomerate sandstones with porosity of 21% and permeability ranging from 10 to 100 mD. The field produces light oil within 40 °API, 30% wax content and 1.14 cP of viscosity. T-119 is the well chosen to be injected due to its structural position that ease flow by gravity force to producer wells.
Forecast simulation based on coreflood result has been conducted for pilot test. However, the result was very pessimistic in predicting incremental oil gain and breakthrough time after compared to pilot result. An attempt to history match the surfactant flood pilot is presented by considering phenomena that is not included in the forecast based on additional lab and field data.
Semberah field, located in East Kalimantan, has been explored since 1974 and developed in 1990. Peak production was reached in late 1998 at 180 MMscfd and 13,000 BOPD. Sharp production decline occurred since 2000 and the field rate dropped from 170 MMscfd to 25 MMscfd in 10 years. Several efforts have been made to sustain decline at economical rate by infill well drilling, horizontal well, and compression system optimization.
Until 2008 drilling is mainly focused in middle area of Semberah along crestal area containing large reservoir tanks with updip position thus favoring high additional reserve and avoiding water table. The well population in south area was very dense with average interval 300 meters. In contrast, to the north crestal areas which have more down dip structure are less developed. The challenge of developing north area is due to limited data from existing wells and the possibility of hitting water reservoir. In 2008, a study was conducted to assess the possibility of applying semi-grid based drilling campaign in north area. The method was based on the combination of deltaic reservoir, new geological understanding and statistical study from previous drilling result. As pilot project, one well was drilling in north area with distance over 800 meters from offset well.
The result was positive, the well encountered new reservoirs or pools with high gas deliverability. The semi-grid based drilling was then focused in north area with various distance 500 - 1000 meters. After 2 years, Semberah field rate increase from 25 MMscfd to 70 MMscfd. A cumulative of 18 BCF gas was produced until 2015 from new reservoirs. A methodology of optimizing well spacing in deltaic reservoir is studied and perfected. The most optimum well spacing to increase the possibility of getting new reservoirs in north area was 500 - 700 meters.
This paper describes the successful implementation of integrated development strategy, which proved to be an effective process to enhance production recovery of a mature asset.
Depletion of the reservoir leads to a decrease in production rate and continuously drops below its minimum critical velocity. At this point, the liquid which flows vertically upward with gas begins to fall back into the wellbore. Liquids accumulation in the tubing creates additional pressure drop and gives more flow restriction to surface. Smaller diameter tubing string (so-called, velocity string) installation is a simple yet successful methods applied in Semberah field to overcome liquid accumulation in wellbore of low production critical gas wells. This paper discussed case studies and screening improvement of velocity strings installation in the observed field. The project delivered an improvement of candidate screening and design to achieve the continuously flow after installation. Case studies were introduced in this paper as example of success and non-success application. Screening improvement was delivered based on post-mortem analysis. Selection candidate included identification of liquid loading symptom by well behavior, critical rate analysis on each wellbore section, and flow regime analysis. Pressure and temperature bottom-hole survey, either at static or flowing condition had to be provided and matched with velocity string model. Evaluation of new critical rate each wellbore section and new flow regime after installation must be calculated. This applied method was proven to extend production life and increase gas cumulative production in observed field. Better understanding of comprehensive well screening is an important factor to enhance success ratio of velocity string installation project. The improved screening based on field experiences can be used as a reference of velocity string selection candidate and design in other liquid loaded gas field. This paper also discussed further opportunities of un-success cases, which apply a tandem de-liquefaction technology: velocity string and wellhead compressor or gas lifted injection for gas well.