The brown field, Mutiara, has been producing for more than 25 years where its reservoirs consist of thousands of lenses as a result of the deltaic sedimentation. Operated by VICO Indonesia, aggressive drilling program was implemented to arrest production decline and to increase additional oil reserves from existing and newly discovered reservoirs. Current practice of producing natural flow will not be sufficient to recover oil from small lenses reservoir. Therefore, integrated works need to be implemented for the oil development in this field.
Splitting focus from gas to oil production is long journey to walk. Major facility upgrading was needed to eliminate gas lift system "blank spot". Additional compressor was also needed to maintain gas lift pressure distribution in southern remote area.
A thorough project planning and procedure are established to ensure optimum field production. Oil zones evaluations followed by prioritization are discussed with well intervention and construction team. After perforation is completed, PCTGL was designed with thorough calculation. It is important to accurately measure pressure drop along gas lift line since PCTGL use single unloader valve which is sensitive to injection pressure changes.
VICO Indonesia cross function team, consisting of Resource Management, Technical Support and Operation, conducted regular bi-weekly monitor during this development phase. It was important to ensure every team carried out their respective responsibility.
Then harvest time is coming; Mutiara oil production delivered average production of 4,981 BOPD in 2016, an increase of average 2,970 BOPD than 2013. The integrated gas lift also managed base production annual decline by delivering above 4,500 BOPD for in 2015. In the last four years, VICO Indonesia also managed to produce cumulative of 5.1 MMBO oil from this project.
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.
Rahim Bima Putra, Nur (National Oilwell Varco) | Leonanto, Raden (National Oilwell Varco) | Markandeya, Sri (National Oilwell Varco) | Ritamawan, Radianto (VICO Indonesia) | Sabri Saragih, Anggi Muhammad (VICO Indonesia)
When drilling wells for hydrocarbon extraction, completing a specific interval of the well in the fastest time possible is a key requirement. One of the main contributing factors for improved performance is the drill bit.
It is well known in the drilling industry that the stress state of the formation around the bit and drilled well is significantly lowered once penetrated by the bit. Conventional single diameter polycrystalline diamond compact (PDC) drill bits are not capable of taking advantage of this reduced effective rock strength.
Dual-diameter bits address the identified challenges through the use of elegant physical principles and offer an efficient, reliable means of drilling. The concentric, dual-diameter design lowers the effective rock strength encountered by the critical shoulder-to-gauge area of the bit's cutting structure.
The smaller pilot section of the bit design drills a pilot hole, which reduces the confinement and thus strength of the rock drilled by the larger reamer section. The reamer section of the bit is able to utilize the bedded pilot bit for stabilization to offset the greater forces associated with larger diameter drilling. The offset blade configuration of the bits also offers 360-degree contact the borehole and helps deliver a gun barrel hole quality.
This paper introduces the development of a unique, two-stage, dual-diameter profile, and polycrystalline diamond compact drill bit for an application in Indonesia. Typically, multiple drill bits are required to finish the section, which consists of abrasive sandstone with some layers of coal. The objective was to improve the drilling performance while also minimizing non-productive time (NPT) for a bit trip.
The paper provides and in-depth evaluation of the bit performance over several field trials. The first bit was run in a motor assembly and improved 14% rate of penetration (ROP) with exceptional dull condition. The drilling parameters indicated that the bit generated higher ROP with lower weight on bit (WOB) compared to other bit types. This performance convinced the operator to run the dual-diameter PDC bit in a more challenging field where its remarkable performance achieved field records. In comparison to the closest offset well, dual-diameter drill bits replaced three-bit runs with 56% longer intervals drilled and improved overall ROP by 41%. In addition, rig time was reduced by 5.3 days. The operator was extremely pleased with the bit performance and decided to use a dual-diameter PDC bit as the primary option to drill this section in every field.
Zhou, Tong (Schlumberger) | Rose, David (Schlumberger) | Quinlan, Tim (Schlumberger) | Thornton, James (Schlumberger) | Saldungaray, Pablo (Schlumberger) | Gerges, Nader (Onshore Petroleum Operations Ltd) | Bin Mohamed Noordin, Firdaus (Onshore Petroleum Operations Ltd) | Lukman, Ade (VICO Indonesia)
A new formation nuclear property, the fast neutron cross section (FNXS), is introduced to the well logging industry. It is a measure of the formation's ability to interact with fast neutrons. For sigma and porosity, the other two commonly used neutron measurements, certain elements tend to dominate, such as B, Cl and Gd for the sigma measurement and H for the porosity measurement. However, for the FNXS measurement, there is no single element dominating the response. This is explained by the complex dependence of neutron interactions on energy and elemental composition. Therefore, FNXS can provide information independent of the other neutron measurements for formation evaluation applications.
FNXS can be measured by a pulsed neutron logging tool that has been designed for that purpose. The corresponding raw measurements are the detected gamma rays that are induced by fast neutron inelastic scattering. However, the purely inelastic gamma ray events cannot be measured directly and are always mixed with the gamma ray events induced by thermal or epithermal neutron capture. It is difficult to consistently separate inelastic and capture gamma ray events in a wide range of downhole conditions. Several critical innovative tool design features are required to overcome this challenge. The detailed physical processes leading to the detected inelastic gamma rays, which involve both neutron and gamma ray transport, were modeled explicitly using Monte Carlo techniques in a wide range of formation and borehole conditions. It was found that the inelastic gamma ray response is dominated by FNXS and thus can be described approximately by FNXS. This approximation can be improved by introducing additional formation properties such as bulk density and atomic density. The tool measurement is characterized based on laboratory data to provide formation FNXS values, with corrections to account for the hole size and casing impact. The impact of other typically unknown borehole conditions, such as cement variation, standoff, and eccentered casing, is assessed using modeling.
Because FNXS values of the rock matrix and water are in the same range, lower for light oil and much lower for hydrocarbon gas, FNXS can be used for a quantitative gas saturation measurement. It is particularly useful for differentiating gas-filled porosity from very low porosity in cased-hole formation evaluation if openhole density is not available. Log examples are provided to illustrate the FNXS measurement applications and performance.
Depletion of the reservoirs leads to a decrease in field production rate. Wells production rate continue to drop below the minimum critical velocity, at which point the liquid that was previously carried upward by the gas begins to fall back. The produced liquid accumulates in the well creating a static column of liquid, therefore creating a backpressure against formation pressure and reducing production until the well ceases production. Down hole Capillary Surfactant Injection (DCSI) is installed on the wells to overcome the liquid loading symptom by generating foam, thereby reducing the surface tension, lowering the fluid density, and lowering critical rate. This paper discusses the improvement to obtain higher success ratio of DCSI installation project on the observed field. Analysis and improvement is done to improve the success of DCSI installation through a comprehensive wells screening, continuity laboratory test, and field optimisation. The screening including the selection of liquid loaded wells & laboratory test (foam test, pH, and salinity test) were corrected with the actual temperature to obtain an accurate foam performance. Correlation is generated to correct the effect of foam build rate and decay rate against critical parameters. Validating well performances with the results of laboratory tests is conducted by continuously field optimisation. The laboratory test is significantly important to screen DCSI well candidate. Surfactant concentration, temperature, & condensate content are critical variables for foam build up and decay performances. Uncertainty variable and un-matching well performance previously not assessed can be reduced by these improvement steps, thus increasing the success ratio DCSI project. The improvement DCSI screening proposed is used as a reference to start the DCSI project to obtain higher success ratio.
VICO Indonesia is an Oil and Gas company which has operated mature fields located in the onshore part of East Kalimantan which has been on production for over 30 years. The fields are dominated by gas reservoirs with a much lower presence of oil reservoirs. Production mechanisms cover from natural depletion to weak and strong water drive, particularly in some of the shallow areas. Recent well completions include single and dual slimhole monobore.
The field is a perfect combination of stratigraphic and structural traps with more than 4000 sandstone reservoirs where around 450 of those are oil reservoirs. The oil recovery factor for these reservoirs is in the range of 10-30%. Oil development in this fields performed using gas lift as the main artificial lift while several wells still flowing naturally. Coiled tubing gas lifted (CTGL) wells contributes to 60-80% of current oil production of 8000 BOPD.
Totally, 50 CTGLs have been installed in VICO Indonesia where most of those considered successful. The main problem found related with initial operation after installation. Lesson learned has been summarized including the design and the procedure for initial operation. Coiled tubing gas lift design and troubleshooting are rarely found in literature. Thus, this paper presents the detail step by step design and how to troubleshoot the possible failure during early operation. This approach exhibits a real benefit to recover more untapped hydrocarbon with more aggressive program.
Mutiara is a mature field located in the onshore part of East Kalimantan which has been on production for over 30 years. The field is dominated by gas reservoirs with a much lower presence of oil reservoirs. Production mechanisms range from natural depletion to weak and strong water drive, particularly in some of the shallow areas. High decline rates are very common, which results in a very dynamic and challenging environment. The main artificial lift used in this field is gas lift. However, this method is not efficient for depleted or high water cut wells. Another issue is oil wells which located in remote areas which need high investment for surface facilities including gas lift line network and sufficient pressure to lift the oil up to the surface. Therefore, more and more wells will be idle without implementation of other artificial lift systems techniques.
Several downhole pumping types have been assessed to tackle these issues such as Electric Submersible Pump (ESP), Progressive Cavity Pump (PCP), and Linear Rod Pump (LRP). Considering hilly swampy conditions of the field that requires more compact type of surface unit and flexible to match displacement rate to well capability as well declines. It is then decided to use LRP to unlock oil potential in idle wells.
The first installation of LRP was on September 2014 in X-1 well, this well is the first well drilled in 1982. This installation succeeds on bringing back the well on production. The application of LRP provides opportunity to unlock oil potential from idle wells in this mature area thus maximizing reserve by gaining a few more hundreds barrels of oil per day during the first year.
Traditional models characterize the modern Mahakam Delta as a mixed river-dominated and tide-dominated delta that is presently prograding (e.g Galloway, 1975; Allen et al., 1976; Gastaldo et al., 1995; Allen and Chambers, 1998) and are commonly used as analogs to interpret subsurface successions. However, a recent quantitative study that describes the modern delta as transgressive and depositing a transgressive succession with very high preservation potential (Salahuddin and Lambiase, 2013) invalidates the use of the modern delta as a viable analog for progradational subsurface successions and suggests that transgressive successions may be relatively common in the subsurface.
The Modern Mahakam Delta
Quantitative hydrodynamic and sedimentologic data demonstrate the transgessive character of the modern delta that causes back-filling of the distributaries and relatively minor reworking of pre-transgression sediment. Very low wave energy in the receiving basin, plus rapid subsidence and burial, limits marine reworking to the uppermost pre-transgression strata and preserves the pre-transgression, progradational distributary and inter-distributary morphology. Ongoing back-filling of the distributaries is generating fining-upward successions that become increasingly marine upward. Current speed, and sediment transport capacity and competence decrease seaward so that the sediment flooring the distributaries is progressively finer downstream, which generates a fining-upward succession as transgression continues (Salahuddin and Lambiase, 2013). These successions also become more marine upward and have excellent preservation potential because of rapid subsidence rates and minor marine reworking.
Sandy back-filled distributary successions are somewhat thinner and closer together in the upper delta plain than in the lower delta plain. As these sands fill the topographically low distributaries, they are laterally adjacent to slightly older, pre-transgression progradational strata. In contrast, inter-distributary areas are developing relatively thin, sandstones directly above pre-transgression progradational strata and separated from it by a transgressive erosional surface generated by marine reworking. The three dimensional geometry of the sandstones within a transgressive succession is expected to be complex and highly dependent on the pre-transgression delta morphology. The back-filled distributary sandstones are sinuous and oriented quasi-perpendicular to the shoreline while the transgressive shoreline sandstones are shoreline-parallel with a lateral extent that is determined by the distributary spacing. Ongoing transgressive lobe-switching means that the back-filled distributary successions are not exactly contemporaneous and that they probably have highly variable thicknesses and lateral extent.
Weatherall, Glyn (VICO) | Halinda, Debby (VICO Indonesia) | Daungkaew, Saifon (Schlumberger) | Suriyanto, Olivia (Schlumberger Data & Consulting Services) | Mas, Cholid (Schlumberger) | Islam, Anzar (Schlumberger)
Significance of Subject Matter
Coal Bed Methane (CBM) has become one of the most important unconventional resources for today petroleum industry since its discovery in many countries including Indonesia. The main challenge for CBM fields is a proper reservoir characterization in coal matrix, cleat and shale layers. Another main challenge is a variation in reservoir productivity from zone to zone. Formation evaluation for this unconventional reservoir is not as straight forward because the evaluation program needs to be adjusted to obtain enough reservoir information for an effective field development plan.
The Dual Packer Formation Testers (FT) can be used to test zones where matrix porosity is too low for a single probe FT such as carbonate and fracture basement reservoirs. However, the use of dual packer FT remains quite a challenge due to time per station, tool sticking risk, and limited packer intervals. This paper reviews the use of Dual Packer FT to evaluate reservoir properties in one of the CBM wells in Asia.
Description of the material
This paper presents the use of Dual Packer FT for an Interval Pressure Transient Test (IPTT) for reservoir pressure, fluid sampling, zone permeability, and also for a stress testing applications. This paper will be more focused on the stress testing technique using Dual Packer FT. This “micro-frac” application in CBM wells plays an important role in providing shale layers’ stress parameters such as a fracture treatment design and an optimal completion design. However, it also has its operational challenges associated for pre-job planning.
Results, Observations, and Conclusions
This paper presents a systematic integration between pressure transient analysis and fracture diagnostic plots utilizing a G-function plot, as well as a Square-Root time plot in this smaller scale of fracturing operations. The output of the analysis including initial breakdown pressure, closure pressure, fracture propagation pressure, initial shut-in pressure, and shale permeability will be discussed and compared with full scale fracturing, drilling leak off tests, and modeling results from geomechanics study. This paper will also address technical and operational aspects of the Dual Packer FT operation in this unconventional reserve.