Mandal, Dipak (Oil & Natural Gas Corporation Ltd) | Baruah, Nabajit (Oil & Natural Gas Corporation Ltd) | Jena, Smita Swarup (Oil & Natural Gas Corporation Ltd) | Nayak, Bichitra (Oil & Natural Gas Corporation Ltd)
Hydrocarbon gas injection into the reservoir is one of the most effective EOR processes. In case of a dipping and light oil reservoir, immiscible gas injection can give further impetus to the oil recovery. Since, average current gas saturation in the subject reservoir has become high due to depletion rendering water injection at this late stage is found to be ineffective, scope of gravity assisted immiscible gas injection as an alternative has been evaluated to assess its impact on reservoir pressure and ultimate recovery.
The present study pertains to a high permeable clastic light oil reservoir with reasonable dip, belonging to an old field of South Assam Shelf of India under production since 1990 with current recovery of 22% of STOIIP. The reservoir being undersaturated with no aquifer support, shows significant decline in reservoir pressure (260 ksc of initial pressure to current level of 50 ksc). Simulation study has been carried out on a fine scale geo-cellular model. Multiple realizations have been created considering combinations of oil producers and gas injection wells assigning varied rates to study the different development scenarios and impact on recovery improvement. The study indicates an incremental oil recovery of about 14% of STOIIP by immiscible gas injection.
Based on the study, immiscible gas injection has been initiated in the reservoir on pilot scale basis through two gas injectors with continuous monitoring. After gas injection during last one year, reservoir pressure increased about 25 ksc and consequently per well productivity also increased. Non-flowing well starts producing and currently sand is producing nearly 25% higher than earlier production before gas injection. Based on the encouraging result from pilot gas injection, decided to expand the process at field level and subsequently drilling of new oil producers after jacking up of reservoir.
The study has brought out that the gas injection into shallower portion of the reservoir yields better sweep efficiency to displace the oil to the deeper portion of the reservoir due to the gravity effects and hence, appropriate locales of the reservoir are targeted for additional input generation to augment the oil recovery.
Depositional environment of a sedimentary sequence plays a vital role in the nature of sediments and distribution pattern of sediments. Environment of deposition is generally determined by sedimentological study, wire line log interpretation from well data of specific locations. The spatial extrapolation in to nearby areas can not be done alone by sedimentological study/ log interpretation. There are a number of techniques / tools available to identify the distribution pattern of sediments deposited in different environments of a stratigraphic sequence. Sequence stratigraphy is now a well established technique for determining sediment distribution pattern in a sedimentary sequence deposited in varied depositional environments. This special technique requires an in-depth knowledge of the subject and sufficient palaeo-geological information about the study area. Often, it becomes difficult to conceptualize the basic framework of the sequence stratigraphy method due to limited regional information and scanty data. As for example in fluvio-deltic-shallow marine conditions with active sea level fluctuation coupled with rapid fluvial sedimentation, sporadic palaeogeographic information hampers conceptualization of geological model. In such a situation another technique can help in solving some of the uncertainties in depositional setting. Basic concepts of Sequence stratigraphy coupled with sand (reservoir) shale (nonreservoir) ratio mapping provide excellent result in identifying depositional pattern of reservoirs units. This is a simple, easy and cost effective way to understand the broad depositional setting of sediments without involving high technology/gadgets.
A case study from an area within the petroliferous Upper Assam Basin of Assam-Arakan geological province of India is presented here.
The Assam Basin is a well known petroliferous sedimentary basin of India. Exploration for hydrocarbon started way back in 1866 and commercial oil was first discovered in 1889 in Digboi. The basin is bounded in the north by the Eastern Himalayas, in the east by the Mishmi Massif, in the south by the Naga-Patkai Hills and in the west by the Mikir Hills and Shillong Plateau (Figure 1). A thick pile of sediments ranging in age from Cretaceous to Pleistocene has been deposited in the Basin. Commercial hydrocarbon productions from Palaeocene to Mio-Pliocene sediments have been established till date.
The Upper Assam Basin is a poly history basin from where hydrocarbons are being produced for more than a century. The first commercial oil discovery of this part of the world came from this basin in the form of Digboi oilfield in 1889. Thereafter, the basin witnessed significant oil and gas discoveries. Exploration work, aimed at different plays, is still continuing in this basin. Tectonically, the basin can be sub-divided into two parts viz. Assam Shelf fore-land and Thrust fold / Schuppen Belt (Himalayan orogenic belt). The geologic formations in the basin primarily comprise of sand & shale alterations of the sediments from Paleocene/Eocene to Recent age. In this study, attempt has been made to create a realistic velocity model using VSP and check-shot data over the entire basin. This velocity model enabled quite accurate time-to-depth conversion of all the major horizons on a regional scale, necessary for basin modeling studies. It also serves as a reasonable input for seismic applications like AVO, Pre-stack inversion, converted —wave seismic and Pre-SDM. It is observed that the pattern of velocity field approximately follows the depth pattern of the basement. The probable reasons behind this particular behavior are studied in detail. The study found that velocity trend is influenced by depositional environment of the basin throughout the history of deposition.
Although the Palaeocene-Eocene reservoirs of the Assam shelf have been prolific producers of oil and gas, the production profiles of various fields have caused concerns because of their departure from the geological model originally envisaged. An attempt is made to understand the temporal and spatial reservoir heterogeneity within a broader depositional model framework using microresistivity image and open hole log data from four fields in the assam Shelf; Baghjan, Katahloni, Bhogpara and Nahorkatia. Using image data, whole cores, dip patterns, openhole logs, image derived neural network facies and image derived textural facies, the key reservoir facies associations are identified. Facies associations in different wells are made use of to reconstruct depositional sequences, which enable to conceive a broader depositional model for the sedimentation of major Plaeocene to Eocene formations, namely Langpar, Lakadong, Narpuh, Prang and Kopili.
This study infers marginal marine to coastal plain channelized sedimentation for the Langpar formation with reservoirs likely to be oriented in a NW-SE to E-W direction. These basal clastics are overlain by lagoon-barrier island to coastal plain channel environment of the Lakadong formation with reservoir orientation along E-W to NW-SE direction. Beach-strand plain to chenier plain depositional environment is encountered in the Narpuh formation with the reservoir appearing to have an extension along NS to NW-SE direction. Overlying Prang and Kopili formations are inferred as restricted marginal marine deposits. The Prang shows occurrences of carbonate facies whereas the Kopili shows feeder channels facies of thick argillaceous sequence. Overall, the Eocene-Oligocene petroleum system seems to have been deposited in a marginal marine depositional setting. Analysis of depositional units in a sequence stratigraphic context suggests that the overall sequence has evolved in a transgressive system. Using a sequence stratigraphic framework allowed us to better define reservoir distribution patterns of the Assam Shelf, and these facies associations may prove useful in future reservoir modeling studies.
Chatterjee, S.M. (Oil and Natural gas Corporation Limited) | Deb, A. (Oil and Natural gas Corporation Limited) | Rao, C.V. (Oil and Natural gas Corporation Limited) | Reddy, P.K. (Oil and Natural gas Corporation Limited) | Sanyal, A. (Oil and Natural gas Corporation Limited) | Yadagiri, K. (Oil and Natural gas Corporation Limited)
Cachar area in the northeastern part of India is a part of Assam-Arakan frontal fold belt. Though the estimated hydrocarbon resource in the area is high, only a small part of it has been converted into reserve. Concealed structures within synclines such as Bhubandar and Banaskandi in the southern part of Cachar are important exploration targets in the area. Up-thrust blocks of both Bhubandar and Banaskandi structures are intensively explored but not the sub-thrust blocks. Similarity of structuring in the area with Triangle zones in other thrust-fold belts of the world is demonstrated. A sub-thrust prospect identified in the area opens up a new exploration avenue.
Cachar area in the northeastern part of India forms a part of the Assam-Arakan frontal fold belt. The area is believed to be endowed with huge hydrocarbon resource but only a small fraction of it has been converted into reserve though exploration started here in the early twentieth century. The main reason for the gap between the reserve and estimated resource in Cachar is that the sub-surface is poorly understood. There is considerable discordance between surface geologic features and the sub-surface in this area arising from tectonic complexities. Poor quality of seismic data is another major handicap. The highlight of exploration so far in Cachar is the discovery of three gas fields, namely, Bhubandar and Banaskandi in the southern part, Adamtila in the west adjacent to the gas fields in Sylhet trough in Bangladesh and an oil field in the northern sector of Cachar. Of the four wells on Bhubandar structure, one well (W-1) and three among the ten wells on Banaskandi structure are commercial gas producers. Because of thrust dominance multiple pools are expected both in the up-thrust and sub-thrust blocks. Up-thrust blocks of both Bhubandar and Banaskandi structures with a number of wells are well explored but there is no well in the sub-thrust blocks.
Cachar-Tripura thrust-fold belt is a part of the central compressive front of Assam-Arakan thrust and fold complex which developed as an accretionary wedge formed on the subducting Indian crust of the eastern leading margin of Indian plate under Burmese sub plate. Strike slip movement prevailed after the initial phase of subduction. The strike slip movement was confined to the east of Kaladan fault and along the N-S trending Sagaing fault while the compressive front propagated westward forming Cachar-Tripura fold belt in its wake. Major structural elements of the area are a series of north-south to NE-SW trending anticlines arranged in en-echelon pattern along a few major lines of folding separated by broad alluvial valley. In addition to the exposed structures, there are a few sub-surface gravity highs, e.g., Bhubandar and Banaskandi in the southern part of Labak syncline, a known source area for generation of hydrocarbons. Such concealed anticlines close to the source area are important exploration targets in Cachar. The area holds a thick column of clastic sediments ranging in age from Paleocene to recent.
World Natural Gas scenario has changed rapidly in the last decade and Natural Gas is set to play an increasing role in meeting the future energy needs as demand rises across the world. Natural Gas demand has increased by 75% over the past twenty years and its share in the total energy consumption is globally expected to increase from 23% in 2002 to 28% by the end of 2005. Pakistan has proven reserves of 796.32 Bcm (28.10 Tcf) and net annual gas consumption of 34.09 Bcm (1.203 Tcf). At present Pakistanâ€™s energy mix comprises 50% of Natural Gas share and there is continuous rise in gas consumption with a target to extend it to about 55%. Paper discusses chronology of Pakistanâ€™s Natural Gas starting from first find in 1952 and development of most extensive transmission and distribution network over the years. Conclusively, the paper would focus to demonstrate the upcoming challenges in Pakistan to meet the growing demands in addition to the opportunities that such challenges bring along.
Natural Gas has already played a vital role in shaping the industry outlook and meeting energy demands in North America, Western and Eastern European countries, and industrialized Asia due to its availability and environmental acceptance. The availability of Natural Gas worldwide and specifically the abundance in Middle East, coupled with its environmental acceptability and various applications across all sectors, will continue to play an increasingly important role in meeting demand for energy in the World. Natural Gas is one of the cleanest, safest, and most useful of all energy sources. Natural gas is the most precious energy source which has extremely efficient BTU input to BTU use ratio. It is also a major feedstock for the production of ammonia for use in fertilizer production and a cleaner fuel choice for power plants.
World Natural Gas Scenario
The World gas scenario has changed rapidly in the last decade. Today Natural Gas is the fastest growing primary energy source. Presently world Natural Gas proven reserves are 6,337 Tcf. More than 75% of world gas reserves are held by ten countries, which represent 40% of the total natural gas exports through pipeline and/or LNG. Pakistan is ranked at number 30 and represents 0.4% of world gas reserves.
A multi-disciplinary approach had been adopted to resolve the exploitationand development strategy for Deohal and its extension oilfield having mainlythe deep Eocene clastic reservoirs which is geologically complex, overpressurized stack of thin sands [by 30-40 Kg/cm2 (assuming 0.1Kg/cm2 /m hydrostatic gradient] interbedded with shale/ carbonaceousshale. An accurate delineation of individual sand in such reservoirs is beyondthe resolution of seismic as these occur at a depth of 3600 to >4000 m andits thickness vary from 2 to 4 m only. The Lithostratigraphic correlation basedon well log is often unreliable/ difficult due to thin and extremeheterogeneous nature of the sediments. Moreover, areal extent of reservoir as asingle unit is difficult to ascertain. The petrophysical properties viz.porosity and permeability substantially deteriorate with increase in depth i.e.below 4000 m.
Initially 3D seismic data was showing a broad faulted anticline with fault500 m to 800 m away from the crestal part. Analyses of pressure transient datashowed barrier nearby and reinterpretation of 3D seismic data confirmed thepresence of minor faults having limited extension.
The Paper presents how transient well test data in conjunction with static3D seismic data, wireline log and dynamic pressure-production data have helpedto workout development strategy for a geologically complex and heterogeneousLower Eocene thin sand reservoir in one of the oilfields in Upper Assam Basin,India.
The Upper Assam basin is a major onshore sedimentary basin located in the Assam-Arakan geological province in the north-eastern part of India. This case history of a high permeability, stratified sandstone reservoir of the Lower Eocene formation in Upper Assam basin illustrates how integrated pressure transient analysis coupled with geological, geophysical, petrophysical and production information can be used for construction of dynamic fluid flow models to provide better reservoir description for reservoir simulation study. Chronostratigraphic and litho-stratigraphic layering of reservoir units for this field done earlier through seismic and log interpretation suggested isolated units. Such a model led to the computation of high primary recovery factors. Independent analysis of well tests was found to yield conflicting results, especially with respect to outer boundary configuration. The reservoirs comprising of fine to medium grained sandstones with interbedded shale/carbonaceous shale are located at around 3600 m depth, generally very thin (1-5 m) and exhibit rapid lateral variation making well-to-well log correlation unreliable in many instances. Consistent modeling of flow barriers through analysis of all available well tests and integration of the same with other geo-scientific data led to a more reliable and consistent interpretation of field observations and facilitated refinement of reservoir description. A 3D-3P reservoir simulation study carried out with this model facilitated in establishing the fact that several sand units/reservoirs in the field under study are in pressure communication with a common aquifer system. This information allowed more reliable estimates of in-place reserves and provided good data for fine-tuning the reservoir model to arrive at reasonable history match. The new model used in reservoir simulation is much more plausible and brings out the importance of using dynamic information for reservoir characterization. Performance prediction of the field based on the new model aided in making realistic assessment of future production profiles and proper planning for field installation of formation water disposal and artificial lift facilities.
Reservoir characterization is the process of defining reservoir properties and geological conditions for evaluating reservoir performance and forecasting future behavior. Between the micro and mega scales of reservoir heterogeneity, it is important to describe and analyze those reservoir characterization parameters that impact fluid flow. This leads to an economically optimized and contextually correct reservoir-engineering program.
The ultimate goal of most reservoir engineering programs is to develop a mathematical model that closely reproduces known reservoir behavior. Such a model can be used as a forecasting and reservoir management tool. These models use large scale averaging to define grid block properties. Well testing is one of the most important means of measuring the properties of a reservoir at such a scale. In recent years, well testing has undergone significant technological changes to evolve from a technique for evaluating permeability and skin to diagnosing reservoir flow models1-2 and assisting reservoir management3.
The Dikom oilfield is an example of a geologically complex field. Crude oil production is obtained from about 3500 m [11500 ft] deep, over-pressured reservoirs located in multiple, stacked, relatively thin sands of about 2 to 5 m [ 7 ft to 16 ft] thickness. Formation permeability varies from as low as 50 md to as high as 6000 md. Thin sands defy reliable sand to sand correlation and identification of reservoir units. Accurate interpretation of sand development pattern is beyond the resolution of seismic data acquisition due to large depths and thin sands. Lithostratigraphic correlation based on well logs is problematic due to very thin sands and extreme heterogeneity. The increased dependence on transient well testing as a tool for reservoir characterization was, therefore, spontaneous.