Devshali, Sagun (Oil and Natural Gas Corporation Ltd.) | Manchalwar, Vinod (Oil and Natural Gas Corporation Ltd.) | Deuri, Budhin (Oil and Natural Gas Corporation Ltd.) | Malhotra, Sanjay Kumar (Oil and Natural Gas Corporation Ltd.) | Prasad, Bulusu V.R.V. (Oil and Natural Gas Corporation Ltd.) | Yadav, Mahendra (Oil and Natural Gas Corporation Ltd.) | Kumar, Avinav (Oil and Natural Gas Corporation Ltd.) | Uniyal, Rishabh (Oil and Natural Gas Corporation Ltd.)
The paper describes the feasibility of revisiting old sands, for improving the recovery factors and enhancing production, which otherwise were already abandoned. The paper also outlines the systematic methods for predicting the onset of liquid loading in gas wells, evaluation of completions for optimization and comparison of various deliquification techniques. ONGC is operating in two gas fields in eastern and western regions in India. Earlier in both the fields, many sands had to be closed/isolated after the wells ceased to flow due to liquid loading in the absence of continuous deliquification. In order to predict liquid loading tendencies and identify opportunities for production enhancement, performance of 150 gas wells has been analyzed. To select most suitable deliquification technique for the present condition, all technically feasible methods have been evaluated and compared in order to get the maximum ultimate gas recovery possible.
After an extensive study, 3 wells were identified in the preliminary stage and SRP was selected as the most suitable Deliquification technique. Initially, two non-flowing wells, which had ceased due to liquid loading and were about to be abandoned, were selected. After SRP installation and sustained unloading of water for about 30 days, these wells started producing 12000 SCMD gas. In the third well, one of the top sands had earlier been isolated due to liquid loading and production history indicated that the isolated sand had a very good potential. Also, production from the well was declining in the current bottom operating sand as well due to liquid loading. Encouraged by the results that deliquification had yielded in the initial two gas wells, the isolated sand interval in the third well was opened again with the aim to revive production. The well was re-completed with SRP with both the reservoirs open. Before deliquification, the well was producing about 15000 SCMD gas from the bottom sand. After SRP installation and continuous deliquification, the well started producing gas at a stabilized rate of 45000 SCMD, thereby resulting in an additional gas recovery of 30000 SCMD for nearly one year as on date. The approach of putting in place continuous deliquification techniques has not only helped in enhancing production from the existing reservoirs, but has also opened up new avenues to revisit the earlier isolated / abandoned reservoirs for possible enhanced recoveries.
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.
SN Structure is one of structure in the oil & gas rich Kutai Basin of East Kalimantan, Indonesia. Since, well SN-1 was drilled then plugged (with oil shows) and SN-2 has just been drilled with target on the Pelarang anticline situated approximately 2.6 kms southeast of SN-1 then plugged and temporary abandoned. The primary objective of SN target was the shallow updip potential of the Late Miocene Balikpapan and Early-Middle Miocene Pulau Balang reservoirs.
In other well, SN-2 the target was 2,355 ftMD vertical well. On 12-1/4″ Open Hole section, there was gas peak and high pressure on depth 475-482 ftMD with MW slightly reach the LOT on last 13-5/8″ casing. While drilling there was a deals with well kick condition that should occurs with MW slightly reach 18 ppg (Last LOT reading). Occurs the kick, gas came out from separator then burnt out. For safety, it has to stop and set the casing 9-5/8″ to depth 738 ftMD, without DST activity. Further now, the SN structure has just shown that it has potential hydrocarbon on its subsurface which need more proven data to get the P50 and P90 for its structure.
Next 8-1/2″ open hole section, the operation must face the well with MW 17.1 ppg which with additional surface pressure, it slightly reach the MW LOT 18.2 ppg. At depth 1,170 ftMD, with MW 17.2 ppg there was kick and well control problem and for safe safety operation reasons, drilling finnaly has to stop. Then it was plugged from depth 1,170 ftMD to depth 738 ftMD and temporary abandonment, caused the MW to occurs the kick and well control has reached 17.6 ppg. On plan program, there is an open hole logging job to indicate and collect data on 8-1/2″ section. But the program cancelled just because the slurry and viscous of MW is very high and the tools can't go down deep to the target depth. SN-2 well now has suspended operation and there is no Testing operation on Well, with gas Hydrocarbon indications. For future, this well is planned for DST job on section depth 315 – 738 ft MD. Further now, the SN structure has just shown that it has potential hydrocarbon on its subsurface.
Its structure is more challenged caused there highly gas peak and some section must occurs kick and well control while drilling. This might caused by fault which acting as a seal, and has been used as a boundary for the P90 area used in the calculation of reserves for the SN-2 Prospect. Its structure must have some G&G studies for having some good parameter and indication, while drilling operation team must have a good design on well schematic and drilling program for the next well on SN structure. Which means have a good and perform of Drilling contractor and materials.
Property distribution of carbonate rock reservoir is a complex thing due to the high level of heterogeneity, but it also becomes the cause that carbonate reservoir turn into a hydrocarbon reservoir with highly potential not only in Indonesia but also in the world. In Indonesia carbonate reservoir known to evolve at a very varied facies, starting from coral reefs, shoals up to bioclastic platform where each reservoir has its own history of diagenesis.
Diagenetic process that works on each reservoir affects the reservoir characteristics that are reflected in the genetic relationship with log characteristics that recorded on each reservoir. Diagenetic process that works generate secondary porosity as; vuggy porosity and intercrystalin dolomite porosity and also microporosity formed by diagenetic processes related to freshwater vadose and marine burial.
Diagenesis analysis conducted in the core data in the form of petrography thin section shows indication that each process of diagenesa that occurred in carbonate rocks if the result is being in comparative with log data it generates specific correlation and has a unique characteristic response to the log; GR, NPHI, RHOB and other conventional logs.
The unique phenomenon can be applied in other wells that have only log data and does not have the core data. By knowing the relationship between the log characteristics and diagenetic process that occurred in each carbonate reservoir, we can be determine where the good location for distribution of reservoir property that will eventually be useful for the development and the hydrocarbons depletion in carbonate reservoirs.
It is estimated that more than 60% of the world's oil and 40% of the world's gas reserves are held in carbonate reservoirs. The Middle East, for example, is dominated by carbonate fields, with around 70% of oil and 90% of gas reserves held within these reservoirs (Schlumberger).
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.
VICO Indonesia operates the Sanga Sanga PSC in East Kalimantan which is on production since 1972. Reservoirs are mostly gas and depleted. Very Low Pressure compression "VLP?? systems, which operate at 15-25 psig suction, are widely installed across all fields. As a result, flowing tubing head pressures in a large number of wells are in the order of 40 psi. Completion tubing sizes range from 2 3/8?? to 4.5?? with the majority being 3.5??. Despite this, a large proportion of VICO's existing gas wells are subject to liquid loading, leading to premature abandonment of producing zones when the gas velocity in the tubing is lower than the critical velocity. This phenomenon is influenced by the tubing size, surface pressure and the amount of associated liquids produced with the gas. Historically, some temporary activities were carried out to overcome this problem. This included the reactivation of wells by flowing to flare and/or dropping foaming agents. The result of this type of "temporary?? application was very variable and inconsistent.
In an effort to continuously optimize the system and reduce the abandonment pressures, a large scope deliquification project was launched in 2006. The project included the application of capillary strings for down-hole chemical injection, plunger lifts, and wellhead compressors. This program was applied across all fields in VICO. The results were very positive in bringing back the production strings previously considered marginal or not producing. The field wide implementation program for both capillary string units and well head compressors was conceived to allow periodic relocation and optimization of the units and the system. As a result, all these deliquification techniques have now become a core element of the Base Production System. They continue to be optimized on a day to day basis and as a whole they are responsible for approximately 10% of the total production from VICO.
VICO has been continuously producing the Sanga Sanga PSC in East Kalimantan since 1972. Its production is primarily gas, which accounts for approximately 80% of the total. Currently the majority of this production comes from very depleted reservoirs. The bottom hole reservoir pressures are mostly within the range of 2 to 3 ppg, hence low surface pressures are required to produce these reservoirs. Very low pressure (VLP) compression systems have been installed at plant station across all fields. The suction pressures of these VLP compressors are usually within the range of 15 to 25 psi, thus the flowing tubing head pressure of most wells flowing to these VLP systems are in the order of 40 psi. This very low pressure system has been successful in maintaining the wells producing for long periods of time.
As time has passed, a large number of wells -even flowing to these VLP systems- started to suffer liquid loading problems. Liquid loading is usually influenced by the amount of liquids associated with the gas production, the tubing size, the surface pressure and, off course, the rate of production, which defines the velocity of both the gas and liquid inside the tubing.
This problem has been a focus area for VICO since a significant proportion of the remaining reserves are located in some of these large depleted reservoirs. In order to overcome these problems, several deliquification techniques have been introduced and implemented since 2001. However, since no systematic approach was initially applied, the results of most of the initial efforts were very variable, and limited success was achieved. Subsequently, a larger and more systematic approach was applied after 2006. This program is still the one being applied today and it is the one responsible for keeping about 10% of the total production from VICO.
VICO Indonesia is the operator of Sanga Sanga Production Sharing Contract (PSC) area in the onshore Mahakam Delta, East Kalimantan, Indonesia since 1968. Over 40 years, the PSC has produced more than 12 TSCF of gas through more than 800 wells to feed the Bontang LNG Plant and domestic market. One of the major fields in the contract area is the Badak Field, which has contributed more than 6 TSCF of gas production.
Badak Field's reservoirs are the analog of the present day's Mahakam delta, and comprise of stacked distributary channel sands deposited in the deltaic environment draping on a four-way dip closure anticline. The shallower stratigraphic interval is dominated by fair to good quality upper delta plain, amalgamated channel sands, with a combination of water and depletion drive mechanism. The deeper stratigraphic intervals are dominated by fair to poor quality lower delta plain, more isolated distributary channel sands and mouth bar. The main reservoir drive mechanism is depletion drive.
As the early development strategy of the Badak Field had been focused mainly on drilling the best reservoirs, those shallow reservoirs in the crestal area, the majority of these reservoirs are now depleted. In contrast, low permeability deeper reservoirs with relatively higher reservoir pressure, still contain significant remaining resources. VICO's depletion challenge is to balance between increasing the recovery from the deeper intervals, whilst continue optimizing the recovery from shallow intervals.
An Integrated subsurface study has been conducted to understand the geological description of the reservoirs, ultimately to unlock the reserves of the deeper low permeability intervals. Several development options have been carefully evaluated, which lead to the implementation of new technologies to optimize recovery, including cluster wells, horizontal wells, and hydraulic fracturing. The results of the implementation of the development strategy and technology have been outstanding. This has helped sustain the Badak Field's decline rate at around 25% annually compared to a 45% natural decline. In 2011, the gas production was successfully maintained at 75 MMSCFD or 3 times the base line of the "do nothing?? case prediction, with more than 55 BSCF of reserves progressed.
The Badak Field, operated by VICO Indonesia, is one of the world's giant gas fields. Located in East Kalimantan, the field lies in the northern part of the Badak - Handil giant anticline. Discovered in January 1972, production started in October 1976 and reached a peak of 1,1 BCFD in December 1990. Up until now, cumulative production has exceeded 6 TCF.
Today, Badak is a very mature gas field which produces 80 MMscfd. The drilling of new wells and the well intervention activities continue to be the main way to maintain production in the field. Most of the reservoirs units, especially the larger ones, have been intensively drained over the life of the field. Only a few of them are producing, but at relatively low rates, due to their significant depletion. Finding zones with remaining production potential has become a much more difficult task, especially if some of these zones have incomplete suites of logs.
In VICO, the improvement in the subsurface analytical methods has proven successful in helping identify additional reservoir opportunities. Recently, a method has been developed to identify "bypassed gas zones?? in shallow reservoirs. This method uses the sonic log as the main tool for analysis. It also incorporates all of the subsurface data that has been acquired through time. The method has proven very successful in the Badak field in areas where no Density-Neutron log has been acquired.
Theoretically, the sonic log can be used as a complimentary tool to identify gas in the reservoirs. The problem arises when trying to differentiate between the event of gas and the effect of poor or under-compacted shallow reservoirs, as in many cases these events will present a similar feature across the sonic log. The development and implementation of these methods have helped significantly to maintain production in the Badak field.
Badak is a giant gas field consisting of more than 180 production layers with more than 530 reservoirs. The cumulative production has reached more than 6 TCF since start up in October 1976. Today, the field is already in very mature production stage, and it has become very difficult to find high deliverability zones to be produced. The location of Badak field with respect to the Mahakam Delta in East Kalimantan is shown in Figure 1.
VICO Indonesia is the operator of the Sanga-Sanga Production Sharing Contract located onshore of the Mahakam delta, East Kalimantan, Indonesia since 1968. Over 40 years the PSC has produced 70% of the estimated original gas in place, supporting Bontang LNG plant. VICO has 7 producing fields, in a complex fluvial deltaic deposition with more than 2700 gas and oil reservoir, mixed of depletion and water drive mechanism reservoir. VICO production peaked at 1.5 BSCFD in 1995 then start to decline. Current production is in the range 385 MMSCFD of gas and 14500 BOPD of liquids from 400 active wells.
In a situation of 46% annual base decline, to fulfill domestic and LNG contractual commitments and to optimize reserve recovery, VICO generated and implemented an integrated and aggressive work program called "Renewal Plan??. This is an integrated approach between reservoir management and technology application; it provides a detail road map to onward development strategy.
The main elements of the plan are extensive development drilling activities (conventional drilling, grid base drilling, cluster well drilling), low permeability reservoir optimization (horizontal well, hydraulic fracturing, radial drilling), production optimization (deliquification technique, permanent coil tubing gas lift for monobore type) and facilities optimization (reducing abandonment pressure by additional compression installation, wellhead compressor, debottlenecking).
Technology application in drilling, completions, production and facilities optimization combine with synergy from multidisciplinary team have resulted in maintaining VICO production decline in the range of 5% (vs 46% base decline), allowing promoting and partially replacing the reserves at an attractive development cost, even after 40 years production life.
This paper will describe the successful implementation of renewal plan in VICO Indonesia, which proved to be an efficient example of better reservoir management for optimum development of mature assets.
The Semberah field is located onshore on the Mahakam delta, East-Kalimantan, Indonesia. It is operated by VICO Indonesia. Reservoirs in this field consist of multi-layered sandstones deposited in a complex fluvio-deltaic environment. After more than 30 years of production, this field has reached a mature stage. Most of the remaining reserves are locked in low permeability reservoirs, on which conventional techniques have not been very effective in depleting the reserves.
These low-permeability reservoirs require technology innovations to economically produce the reserves. A comprehensive approach was taken by a multidisciplinary team of geologists, reservoir engineers, drilling and completion engineers to assess options for technology application and identify candidate reservoirs for low-perm zone development. Several technologies were considered including horizontal wells, radial jetting, and hydraulic fracturing. Of the technologies applied, horizontal well was proven as the most effective technique to increase productivity of these low-perm reservoirs. One horizontal well was successfully executed and intersected 867 ft of lateral section into the target reservoir. The well was put on production giving exceptional results. For comparison, the well increased the gas production rate of the target reservoir from 1 MMSCFD using conventional techniques to 15 MMSCFD using horizontal drilling. Currently, the horizontal well is still producing. Cumulative production has reached in excess of 7 BCF after a period of 6 years. Other technologies, such as radial jetting and hydraulic fracturing, were also applied but they recover moderate-size gas reserves with less successful results. Lessons-learned were captured and several elements of improvement were identified for future application.
This paper illustrates the lessons learned in searching for the fit-for-purpose technology application to unlock gas reserves in low-permeability reservoirs in a geologically complex environment such as the Semberah field.