Barmer Basin Research Articles

Challenges and opportunities of wireline formation testing in tight reservoirs: a case study from Barmer basin, India

Tight reservoir exploration in Barmer basin has huge potential with possible in place volumes of multi billion barrels in reservoirs across the Mesozoic to Cenozoic stratigraphic levels. These tight reservoirs (permeability in the range of 0.01–10 mD) are ideal fraccing candidates for commercial production. One of the critical challenges in tight reservoir exploration is early assessment of permeability and reservoir fluid type identification through wireline formation testing (WFT) to determine flow behavior, frac optimization and expected deliverability after fraccing. The most prospective Barmer Hill (BH) and Fatehgarh (FAT) tight formations from the basin have been tested with new 3D radial probe WFT tool providing significant time and cost optimization opportunities. Good quality fluid samples with very low contamination levels were extracted with less rig time and operational costs from very low permeable BH formation (0.18 mD/cP mobility) and FAT formation (0.35 mD/cP mobility) in 150 and 200 min respectively. 3D radial probe and dual packer module based WFT job were compared for their efficiencies in similar environment. The results show that 3D radial probe has less inflation time (~1/5th), quick fluid detection (~1/10th time), quick and reliable packer deployment, focused fluid flow regime to address the formation heterogeneity and minimum hole sticking issues due to mechanical arms around the probe. In short, 3D radial probe can address both the uncertainties of WFT in tight reservoirs and optimized well testing and frac design for cost effective field development.

Peat swamps at Giral lignite field of Barmer basin, Rajasthan, Western India: understanding the evolution through petrological modelling

The lignite samples collected from Giral lignite field of Barmer basin have been subjected to petrological investigation. The data generated has been discussed to understand the evolution of the paleomires of these lignites. The present study reveals that these low rank C coals are chiefly composed of huminite group macerals, mainly telohuminite and detrohuminite, while liptinite and inertinite group macerals occur in subordinate amounts. Not much variation in the maceral composition from Seam-I to Seam-VIII has been observed. Barmer lignites are characterized by a very high GI (>10) and moderate TPI indicating topogenous mire in the basin which was permanently flooded. The GI and TPI values and the petrography-based facies critical models indicate that these lignites originated mostly under wet forest swamp to clastic marsh having telmatic to limno-telmatic conditions with a moderate rate of subsidence and a very slow fall in ground water table. Further, the GWI and VI values are suggestive of mesotrophic to rheotrophic hydrological conditions having the dominance of herbaceous to marginal aquatic vegetation. There were spells of periodic drowning of peat especially during the formation of Seam-VII. Moderately high concentration of calcium in these lignites along with the presence of framboidal pyrite indicate enhanced sulphate-reducing bacterial activity present in carbonate and sulphate-rich waters in the basin during peat formation.

Peat biomass degradation: Evidence from fungal and faunal activity in carbonized wood from the Eocene sediments of western India

An integration of reflected light and transmitted light study of Eocene lignite along with Scanning Electron Microscope (SEM) examination of carbonized wood from Kapurdi lignite of the Barmer Basin has yielded abundant fungal components and arthropod appendages. The carbonized wood section under SEM shows tyloses, a physiological process as a response to fungal infection. Scolecodonts and annelid body parts were also recovered from the studied sediments, indicating the peat biomass was a thriving habitat for detritivores. In petrographic examination of the lignite beds which underlay and overlay the carbonized wood section, the funginite is found to be associated with resinite, indicating that the funginite inclusion was not accidental but encapsulation of fungi by exuded resin of the plant as a defense mechanism. Funginite is found in higher percentages in detrohuminite (attrinite) groundmass in lignites. The degradation of the humic matter is attributed to the fungal infestation as well as faunal activity in the peat mire. This fungal–faunal interaction resulted in alteration of the organic matter and origin of macerals belonging to inertinite group.

Shallow Marine Trace Fossils from Mandai Formation of the Barmer Basin, District -Jaisalmer, Western Rajasthan, India

Thirteen well-preserved trace fossil species namely Thalassinoides horizontalis, Thalassinoides suevicus, Ophiomorpha nodosa, Ophiomorpha borneensis, Palaeophycus heberti, Palaeophycus tubularis, Planolites, Planolites montanus, Planolites beverleyensis, Planolites annularis, Siphonites, Paleomendron, and Phycodes palmatum have been reported from Mandai Formation of the Barmer Basin at Mandai area, western Rajasthan, India. The present study area is located about 15 km southwest of Fatehgarh town on Fatehgarh –Jhinjinyali tar Road. The Mandai Formation is 27 m thick lithostratigraphic unit deposited in the north-western part of the Barmer Basin and overlies on Early Palaeocene Bariyara -Dharvi -Sajit Member of the Akli Formation and overlain by Giral -Thumbli Member of Akli Formation of Early Eocene. The Mandai Formation has mixed siliciclastic, minor carbonate and phosphorite facies and its starts with bioturbated medium to fine grained ferruginous sandstone at the base. These trace fossils are preserved of full relief in yellowish to dark brown medium to fine grained ferruginous sandstone and greyish yellow coarse and coarse to medium grained calcareous sandstone. The entire ichnogenera shows shallow marine depositional environment of Mandai Formation of Barmer Basin. No age can be assigned on the basis of these trace fossil as they have long range (Cambrian to Recent).

Near Shore -Shallow Marine (Ophiomorpha and Margaritichnus) Trace Fossils from Fatehgarh Formation of Barmer Basin, Western Rajasthan, India

Two trace fossils namely Ophiomorpha and Margaritichnus have been reported from the Bariyara section of the Fatehgarh Formation of Barmer Basin. Here the Margaritichnus trace fossil sp. is the first record from the western Rajasthan. The present study area is located about 6 km south of Fatehgarh town and 70 kms north of Barmer on Bramer–Jaisalmer road. The Ophiomorpha trace fossils are found in white fine grained calcareous sandstone from lower siliciclastic sequence while Margaritichnus trace fossils occurs in dark brown medium to fine grained ferruginous sandstone of middle phosphorite - siliciclastic sequence of the Fatehgarh Formation of Barmer Basin. The Ophiomorpha trace fossils were considered as crustaceans and shrimps whereas Margaritichnus were mainly produced by worm–like deposits feeders such as sipunculids and priapulids or possibly hydrozoa. The ichnological and sedimentological investigations suggests near - coastal shallow marine depositional environment for the Fatehgarh Formation of the Barmer Basin. It is difficult to attribute a more specific age of Bariyara section of Fatehgarh Formation because of the long stratigraphic range of Margaritichnus (Permian-Cretaceous) and Ophiomorpha (Permian-Recent) as attributed the Fatehgarh Formation to the Cretaceous age on the basis of microvertebrate assemblages recorded from the same Bariyara section.

Delineating thin sand connectivity in a complex fluvial system in Mangala field, India, using high resolution seismic data

The Mangala field is located in the northern part of the onshore Barmer Basin in India. The primary reservoir in the field is the Fatehgarh Formation, deposited during the rifting phase that created the Barmer Basin during the Late Cretaceous to Early Paleocene period. The majority of reservoired oil is con¬tained within the Upper FM1 member of the Fatehgarh Formation, composed of single storey and multi-storey stacked, meandering channel sands. The average gross thickness of FM1 is 80 m, and individual sands vary in thickness from 3 to 7 m, with net-to-gross ratio ranging from 18% to 78% due to inherent heterogeneity within FM1 as evident from core data. For such a heterogeneous fluvial system, correlation of fluvial channel sands and flood plain shales poses a major challenge for reservoir characterization when based on well data alone. Detecting or mapping the lateral continuity of these thin fluvial channel sands is difficult because they are below seismic resolution in conventional seismic data. We applied sparse-layer reflectivity inversion (Zhang and Castagna, 2011) to the 3D stack PSTM data, which resulted in a data¬set with improved detectability and resolution. The 7-50 Hz bandwidth of the input seismic data increased to 7-100 Hz through the inversion process. Results were validated using well log and production data. The new data contributed to greater understanding of the lateral connectivity of the FM1 fluvial channel sands, and enabled geobody extraction for reservoir static modelling.

Geochemical characterization of oils and their source rocks in the Barmer Basin, Rajasthan, India

The Barmer Basin is a failed continental rift of late Cretaceous–Eocene age in Rajasthan, NW India, containing prolific hydrocarbon resources, with 33 discoveries having been made in the last decade. The basin is predominantly oil-prone, although gas discoveries have been made in the deeper parts of the basin. Oils in the Barmer Basin are highly waxy, a result of the lacustrine nature of the source rocks that dominate the sedimentary fill of the basin. Detailed interpretation of the molecular composition of the oils defines three main oil groups that can be related to differing sources. The oils are all distinctively lacustrine in origin, although differing in specific source-facies characteristics. All of the oils are isotopically light, mostly in the −29‰ to −33‰ range. Most oils in the northern Barmer Basin (groups 1A and 1B) are interpreted to have been generated from the Late Paleocene Barmer Hill Formation, an excellent oil-prone source rock with predominantly Type I lacustrine algal and bacterial kerogen. Group 2 oils are subordinate in abundance, occurring only in the southern part of the basin, and are interpreted to be at least partly sourced from the overlying Early Eocene Dharvi Dungar Formation, which is characterized by mixed Type I and Type III kerogen, and attains oil maturity only in the southern basin. Group 3 oils are less common, and are of higher maturity than the Group 1 oils, but also appear to have been generated from the Barmer Hill Formation where it was buried more deeply in the central and southern parts of the basin. However, recognition of probable Mesozoic sediments in sub-basins beneath the Tertiary Barmer Basin introduces a further source-rock candidate for the Group 3 oils. A high maturity hydrocarbon charge that is recognized in the gasoline-range hydrocarbons in the Group 2 oils of the southern Barmer Basin may also be from a Mesozoic source rock, or from the Barmer Hill Formation that is much more deeply buried in this part of the basin than in the north, and represents a more mixed oil- and gas-prone source.

Q&A with Mayank Ashar, Managing Director and Chief Executive Officer, Cairn India

Q&A Mayank Ashar is the managing director and chief executive officer (CEO) of Cairn India. He has more than 36 years of experience in the international oil and gas industry. He previously served in various senior management and top leadership roles in global organizations such as BP, Petro-Canada, and Suncor Energy. He also served as the CEO and president of Irving Oil. In recognition of his operational excellence and large-scale project management leadership in the oil sands project with Suncor Energy, Ashar was named the “Operations Executive of the Year” by the Canadian Business magazine in 2003. Ashar holds bachelor’s degrees in chemical engineering and philosophy and economics, and master’s degrees in engineering and business administration from the University of Toronto. What are Cairn India’s major projects? Cairn India is one of the largest oil and gas exploration and production (E&P) companies in India, contributing approximately 27% of India’s domestic crude oil production. With our affiliates, we have been operating for more than 2 decades, playing an active role in developing India’s oil and gas resources. Our discovery of the Mangala field, the largest onshore crude oil discovery in India in more than 2 decades, opened up the prolific Rajasthan block. Since the resumption of exploration in 2013, Cairn India has made more than 12 discoveries. The total discoveries in Rajasthan alone are 37. The Rajasthan block is situated in the Barmer basin. The block contributed about 23% of India’s domestic crude oil production in FY 2015 [from April 2014 to March 2015]. To maximize the potential of the block and enhance ultimate recovery, Cairn India has initiated one of the world’s largest polymer flood EOR [enhanced oil recovery] programs in the Mangala field, which is the largest discovery made in the block to date. The polymer injection has started and is expected to lead to an increase in production from the field in FY 2016. There are plans to implement similar floods in the other two major fields, Bhagyam and Aishwariya. Apart from its oil reserves, there is a significant gas resource potential in our Rajasthan block. Together with our joint venture partner Oil and Natural Gas Corp. (ONGC), Cairn India is working toward creating appropriate infrastructure to monetize the gas potential, aiming to double gas production over this fiscal year. In addition, we have plans to drill 42 wells over the next 3 years and build a new processing terminal to increase production to approximately 100 million scf/D. The management committee has approved the Raageshwari deep gas field development plan for 100 million scf/D and contracting for this project is currently under way.

The discovery of the Barmer Basin, Rajasthan, India, and its petroleum geology

The discovery of oil and gas in the Barmer Basin in northwest India was one of the more significant global discoveries in the decade 2001–2010. The basin’s presence was suspected from gravity and magnetic data in the late 1980s but not confirmed until 1999 from seismic and drilling. The basin is a lacustrine failed rift. Biostratigraphic data, however, indicate it was intermittently connected to marine waters via either the Cambay Basin, the Kutch Basin, or across the Devikot high, temporarily forming a large, shallow estuary. At least six major tectono-stratigraphic events have caused relative lake level falls and translation of clastic reservoirs basinward. Upward of 6 km (∼20,000 ft) of Cenozoic and Mesozoic sedimentary rocks have been preserved. Prolific source rocks occur from the Mesozoic through Eocene strata. Tectonically, the basin is divided into a northern and a southern province. The north province continues to undergo inversion and erosion, and has not been buried as deeply as the south. Kinetics of the major source facies in the north are substantially different from those in the south, as well as the present-day and paleo-heat flow. These differences have made the northern part of the basin predominantly an oil province and the southern part a mixed oil and gas province. The prolific Paleocene Fatehgarh Formation contains the bulk of the 7.3 billion barrels of stock tank oil in place (STOIP) identified to date, but other reservoirs from the Mesozoic to the late Cenozoic are common and may yield significant future resource additions.

Diffusion Model Coupled with the Flory–Huggins–Zuo Equation of State and Yen–Mullins Model Accounts for Large Viscosity and Asphaltene Variations in a Reservoir Undergoing Active Biodegradation

A very large monotonic variation of asphaltenes and viscosity has been measured by downhole fluid analysis (DFA) in crude oils in five-stacked sandstone reservoirs in the northern part of the Barmer Basin, northwest India, undergoing active biodegradation; each of the five-layered sand bodies shows overlaying fluid gradients with depth providing replicate validation of the measurements. Fluid data from four wells across the field shows that the gradients are uniform across the formation. The crude oil in the upper half of the oil column exhibits an equilibrium distribution of asphaltenes matching predictions of the Flory–Huggins–Zuo Equation of state (FHZ EoS) with the gravity term only using asphaltene nanoaggregates of the Yen–Mullins model. However, the bottom half of the reservoir reveals a large asphaltene gradient approximately three times larger than the equilibrium predictions from the FHZ EoS. This increase in asphaltenes creates a very large (8×) viscosity gradient and is a major production conc...

Geology and regional significance of the Sarnoo Hills, eastern rift margin of the Barmer Basin, NW India

AbstractThe Barmer Basin is a poorly understood rift basin in Rajasthan, northwest India. Exposures in the Sarnoo Hills, situated along the central eastern rift margin of the Barmer Basin, reveal a sedimentary succession that accumulated prior to the main Barmer Basin rift event, and a rift‐oblique fault network that displays unusual geometries and characteristics. Here, we present a comprehensive study of Lower Cretaceous sedimentology on the basin margin, along with a detailed investigation of rift‐oblique faults that are exposed nowhere else in the region and provide critical insights into Barmer Basin evolution. Lower Cretaceous sediments were deposited within a rapidly subsiding alluvial plain fluvial system. Subsequent to deposition, the evolving Sarnoo Hills fault network was affected by structural inheritance during an early, previously unrecognised, rift‐oblique extensional event attributed to transtension between India and Madagascar, and formed a juvenile fault network within the immediate rift‐margin footwall. Ghaggar‐Hakra Formation deposition may have been triggered by early rifting which tectonically destabilised the Marwar Craton prior to the main northeast–southwest Barmer Basin rift event. The identification of early rifting in the Barmer Basin demonstrates that regional extension and the associated rift systems were established throughout northwest India prior to the main phase of Deccan eruptions. Inheritance of early oblique fault systems within the evolving Barmer Basin provides a robust explanation for poorly understood structural complications interpreted in the subsurface throughout the rift. Critically, the presence of syn‐rift sedimentary successions within older oblique rift systems obscured beneath the present‐day Barmer Basin has significant implications for hydrocarbon exploration.

Increasing the effective bandwidth of seismic data through sparse-layer inversion: A case study from Mangala field, Rajasthan, India

Mangala field is in the northern part of the onshore Barmer Basin in India. The primary reservoir in the field is the Fatehgarh Formation, deposited in the rifting phase that created the Barmer Basin during the Late Cretaceous to early Paleocene period. The majority of reservoir oil is contained within the upper FM1 member of the Fatehgarh Formation, composed of single-story and multistory stacked, meandering-channel sands. These sands vary in thickness from 3 to 7 m, with net to gross ranging from 18% to 78%. For such a heterogeneous fluvial system, correlation of floodplain shales and fluvial sands poses a major challenge for reservoir characterization when based on well data alone. Conventional 3D seismic data do not resolve the thin FM1 sands. For more accurate reservoir modeling, various techniques, which included sparse-spike inversion and spectral decomposition, were attempted with limited success. Sparse-layer reflectivity inversion performed on 3D stack PSTM seismic data, however, resulted in improved detectability and resolution and has provided a greater understanding of the lateral continuity of these thin fluvial reservoir units. The 7- to 50-Hz bandwidth of the input seismic data increased to 7 to 100 Hz by the inversion process. The improved imaging of channel geometries has enabled geobody mapping and their input into a revised geologic model.

Palynofacies characterization for evaluation of hydrocarbon source rock potential of Lower Paleogene (Thanetian-Ypresian) sub-surface sediments of Barmer Basin, western Rajasthan, India

This paper deals with the hydrocarbon source rock evaluation and depositional environment of Lower Paleogene sub-surface sediments from borehole MMK-26 of Barmer Basin, Rajasthan. Hydrocarbon potential of these sediments are estimated on the basis of plant derived Sedimentary Organic Matter (SOM) analysis. The palynofacies analysis indicate that the sediments are rich in organic matter with amorphous organic matter constituting the majority of the SOM in the lower part of the borehole where as the phytoclasts dominate in the upper part. The dominance of sapropelic facies (Amorphous Organic Matter) at a depth of 152 m and below suggests that these sediments are a good source for hydrocarbon generation. Further the categorized palynofacies components are plotted on Tyson's Amorphous Organic Matter-Phytoclast-Palynomorph diagram which reveal that the studied sediments are characterized by type-II (oil generating) and type – III kerogen deposited in a dysoxic – anoxic shelf. Thermal Alteration Index (TAI) values were determined to asses the organic maturity of the sediments and a maturation value of 2.80–3.0 for the lower part of the bore core suggest that the sediments have attained an optimum maturation level to produce hydrocarbons. The increasing frequency of marine palynomorphs in association with continental components indicates a transgressive phase of sea level during the deposition of the studied sediments.

Complex rift geometries resulting from inheritance of pre-existing structures: Insights and regional implications from the Barmer Basin rift

Structural studies of the Barmer Basin in Rajasthan, northwest India, demonstrate the important effect that pre-existing faults can have on the geometries of evolving fault systems at both the outcrop and basin-scale. Outcrop exposures on opposing rift margins reveal two distinct, non-coaxial extensional events. On the eastern rift margin northwest–southeast extension was accommodated on southwest- and west-striking faults that form a complex, zig-zag fault network. On the western rift margin northeast–southwest extension was accommodated on northwest-striking faults that form classical extensional geometries.Combining these outcrop studies with subsurface interpretations demonstrates that northwest–southeast extension preceded northeast–southwest extension. Structures active during the early, previously unrecognised extensional event were variably incorporated into the evolving fault systems during the second. In the study area, an inherited rift-oblique fault transferred extension from the rift margin to a mid-rift fault, rather than linking rift margin fault systems directly. The resultant rift margin accommodation structure has important implications for early sediment routing and depocentre evolution, as well as wider reaching implications for the evolution of the rift basin and West Indian Rift System. The discovery of early rifting in the Barmer Basin supports that extension along the West Indian Rift System was long-lived, multi-event, and likely resulted from far-field plate reorganisations.

Harvesting Oil in India's Rajasthan Desert

The Thar Desert in India’s western state of Rajasthan is a desolate region characterized by wind-blown sand dunes. The state is a major tourist attraction, drawing millions of visitors annually to tour forts of medieval kingdoms and visit camel fairs. It is here that Cairn Energy, a Scottish oil company, took over a production-sharing contract (PSC) from Shell in 2003 and developed a major oilfield that has recoverable reserves of at least 1 billion BOE. The major oil companies have conducted little wildcat exploration in South Asia. From 1980 to 1991, the majors drilled 8,000 wells in Southeast Asia, but only 12 in South Asia. Indigenous exploration in Rajasthan began with an inconclusive exploration attempt by the government of India in 1955. In 1988, Oil India discovered natural gas near the town of Jaisalmer and has been producing 0.6 million sd m3/d since 1996. Floated on the London Stock Exchange in 1988, Cairn Energy first entered South Asia by signing a PSC with the government of Bangladesh. In 1997, during a swap of properties with Shell, Cairn acquired a 10% interest in the Rajasthan PSC, which Shell had initially signed with the government of India in 1995. The PSC covered block RJ-ON-90/1 consisting of an initial area of almost 12 000 km2—3111 km2 is now included in the development area, with India’s public sector oil company, Oil and Natural Gas Corporation, holding 30% ownership. After the discovery of the Guda field in 1999, Cairn increased its participation to 50% and eventually took over Shell’s remaining share in 2003 at a cost of USD 7.25 million and became the block’s operator. “Drill Till You Drop” Strategy The geology of the block in Rajasthan’s Barmer basin consists of channel sands stacked on top of one another to create a fluvial reservoir that has high permeability (1–25 darcy) and high porosity. From 2004, Cairn adopted a “drill till you drop” strategy. In January 2004, the company made its initial Mangala discovery with the 16th well in the basin. Following the drilling of appraisal wells, 3D-seismic-data analysis, and well tests, Mangala was confirmed as the largest oil discovery in India since 1985. The Mangala reservoir has a 150 m oil column of medium gravity (20–28°API) viscous crude (9–17 cp) with sulfur content of about 0.1%. The crude has high paraffin content that makes it suitable as a secondary feedstock for refineries, but pipelines and trucks carrying the crude require heating and insulation. Up to 2005, the company drilled more than 140 wells in Rajasthan with a yield of 25 discoveries. In addition to Mangala, Cairn’s major discoveries are Bhagyam and Aishwariya, with 22 other fields including Guda, Saraswati, Raageshwari, Greater Raageshwari, and Kameshwari. In August 2009, the Prime Minister of India, Manmohan Singh, joined Cairn Energy Chief Executive Bill Gammell in inaugurating oil production from the Mangala field.

Waterflooding Viscous Oil Reservoirs

Summary In 2004, the large Mangala, Aishwariya, and Bhagyam oil fields were discovered in the remote Barmer basin of Rajasthan, India. The fields contain light, paraffinic crude oils with wax appearance temperatures only 5°C less than reservoir temperatures and in situ viscosities that range from 8 to 250 cp. As these were the first significant hydrocarbon discoveries in this part of India, there were few analog performance data available. Development plans for the fields are based on hot waterflooding to prevent problems with in situ wax deposition, with production startup in 2009. This article presents some waterflood results from viscous oil fields around the world, benchmarks the expected performance of the newly discovered Rajasthan fields to this database, and discusses several issues associated with waterflooding viscous oils. Given that the Rajasthan oils have some properties that might be considered "unusual" and potentially troublesome for waterflooding and that there are no long-term production data or a history match of waterflood performance in hand, these benchmarks were considered important reality checks. In fact, fields with similar or much higher viscosities are waterflooded routinely with excellent recoveries in Canada, the USA, and elsewhere.

The geology of the Barmer Basin, Rajasthan, India, and the origins of its major oil reservoir, the Fatehgarh Formation

ABSTRACT With the Mangala oil discovery in 2004, Cairn established the Barmer Basin of Rajasthan as a major new hydrocarbon province. Most reserves are contained in fluvial sandstone reservoirs of the Fatehgarh Formation, which probably ranges in age from Late Cretaceous to Early Paleocene. The Fatehgarh sandstones were mainly derived from reworking of Mesozoic sandstones at the northern end of the Barmer rift, but with some volcaniclastic input probably derived from Deccan volcanic rocks within and on the margins of the rift. These thick, quartz-rich, high porosity and permeability sandstones provide an excellent oil reservoir in the north of the Barmer Basin, but the increasing volcanic influence further south causes reservoir quality and thickness of net sand to deteriorate. This paper relates how the tectonic and volcanic evolution of the northwest margin of the Indian plate has influenced the depositional trends which have resulted in formation of this world class reservoir.

Palynology of Lower Palaeogene (Thanetian-Ypresian) coastal deposits from the Barmer Basin (Akli Formation, Western Rajasthan, India): Palaeoenvironmental and palaeoclimatic implications

The 32-m thick sedimentary succession of the Paleocene-Eocene Akli Formation (Barmer basin, Rajasthan, India), which is exposed in an open-cast lignite mine, interbed several lignite seams that alternate with fossiliferous carbonaceous clays, green clays and widespread siderite bands and chert nodules. The palynofloral assemblages consist of spore, pollen and marine dinoflagellate cysts that indicate a Thanetian to Ypresian age. The assemblage is dominated by angiospermic pollen and specimens showing affinity with the mangrove Palm Nypa are also very abundant. The Nypa-like pollen specimens exhibit a wide range of morphological variation, some of the recorded morphotypes being restricted to this Indian basin. Preponderance of these pollen taxa indicates that the sediments were deposited in a coastal swamp surrounded by thick, Nypa-dominated mangrove vegetation. The dispersed organic matter separated from macerated residues indicates the dominance of anoxic conditions throughout the succession, although a gradual transition to oxic conditions is recorded in the upper part.

Very Low Water Saturations Confirmed in Sandstones

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 113162, "Very Low Water Saturations Within the Sandstones of the Northern Barmer Basin, India," by T. O'Sullivan, SPE, Cairn India; R.J. Zittel, SPE, Cairn Energy; D. Beliveau, SPE, Cairn India; S. Wheaton, SPE, Tullow Oil; H.R. Warner Jr., SPE, and R. Woodhouse, SPE, Independent Consultants; and B. Ananthkrishnan, Cairn India, prepared for the 2008 Indian Oil and Gas Technical Conference and Exhibition, Mumbai, 4-6 March. The paper has not been peer reviewed. The Mangala, Bhagyam, and Aishwariya (MBA) fields were discovered in 2004 in the northern Barmer basin of Rajasthan, in northwestern India. The data acquired from field wells enabled a precise estimation of oil initially in place. Techniques are presented that allow estimating the oil initially in place more precisely and revising upward by 12%. Introduction The MBA fields are part of a series of simple, tilted fault-block traps formed within the rifted, Tertiary Barmer basin. Wells encountered gross oil columns in excess of 500 ft within the Fatehgarh sandstones of Late Palaeocene age. The Fatehgarh sandstone consists of interbedded sands and shales and has been subdivided into the lower Fatehgarh sandstone dominated by well-connected sheet-flood and braided-channel sands and the upper Fatehgarh sandstone dominated by sinuous, meandering, fluvial-channel sands. The sands consist almost entirely of mature quartz grains, with virtually no diagenetic alteration, high primary porosities, and excellent permeabilities. Porosities range from 17 to 33% (average 26%) with in-situ permeabilities of 200 md to more than 20 darcies (average 5 darcies). Oil from the MBA fields is waxy sweet crude with gravity ranging from 18 to 20°API close to the oil/water contact (OWC), where the crude has been slightly biodegraded, to 29°API higher in the oil column (average of 27°API). The crude has a low gas/oil ratio of approximately 180 scf/bbl, and the in-situ oil viscosity above the biodegraded zone ranges from 9 to 22 cp. An appraisal program was carried out in 2004–05, with the drilling of 20 wells, acquisition of 3D-seismic surveys, and an extensive coring and testing program including multiwell-interference tests. Areal-interference tests between wells separated by up to 4,900 ft have confirmed excellent lateral continuity within the Fatehgarh reservoir. Test rates in excess of 5,000 BOPD with limited drawdown have been achieved from MBA-field wells, confirming the high deliverability of the reservoir as inferred from logs and demonstrated with core data. Available Data Log Data. All MBA-field wells have full logging suites as well as image-log data. Eighteen wells have nuclear-magnetic-resonance (NMR) data. Fourteen wells were drilled with a water-based mud (WBM) containing appreciable amounts of potassium (>20,000 ppm), either in the form of potassium chloride or as potassium sulfate. The remaining wells were drilled with a synthetic-oil-based mud (SOBM), including wells Mangala-7ST and Bhagyam-5, which were fully cored across the reservoir unit.

Technology Update: Wireline Sampling Technology Enables Fluid Sampling Without Contamination

A focused sampling technique using a new wireline sampling tool was applied successfully in the Cairn Energy-operated Bhagyam field, Rajasthan, northwest India. Favorable results were achieved in this field, formation characteristics of which—highly viscous, waxy crude and oil-based mud (OBM)—had presented numerous challenges in obtaining good representative reservoir-fluid samples, even after long pumping times. Of the 18 samples collected from two wells, 83% were of pressure/volume/temperature (PVT) quality, and 33% of the samples showed zero mud-filtrate contamination. Discovered by Cairn Energy in 2004, the Bhagyam field is one of 19 fields in the Barmer basin (Fig. 1). The high-permeability Fatehgarh sandstone is the basin's main hydrocarbon reservoir. Cairn Energy currently estimates oil reserves in this main reservoir (in three major fields) at 1.5 billion bbl, with reserves in Bhagyam field amounting to 25% of the total. The reservoir is saturated and exhibits compositional grading of oil. Hence, its crude-oil properties vary widely, from 15°API in the north to 52°API farther south. Although Bhagyam oils are not as dense as other heavy crude, with a 21–31°API oil-density range, they have high wax content that gives them a high viscosity and pour point. Early in the exploration and development cycle, high-quality, representative reservoir-fluid samples provide essential information about the properties of hydrocarbon fluids, such as saturation pressure, density, viscosity, and gas/oil ratio (GOR). During the early development phase, an operator's determination of actual reservoir-fluid properties is critical for optimization of its well-completion and production-facility designs. The formation characteristics and highly varied, highly viscous oils at Bhagyam presented challenges in acquiring representative, PVT-quality samples. The high wax content also made sampling difficult with both traditional formation testers and drillstem-test samplers, particularly because OBM drilling was used to avoid shale collapse in the reservoir section. While drilling, contamination from miscible drilling-mud filtrate occurs when sampling oil in OBM wells, still presenting the biggest risk in obtaining good reservoir-fluid samples. During sample collection, OBM filtrate is collected with reservoir fluid, resulting in significant mud-filtrate contamination. This drastically reduces the sample quality and makes PVT laboratory analysis unreliable and often incorrect. When attempting to sample with conventional openhole sampling techniques in the Bhagyam field, long pumping times did not achieve good, representative samples. Of the more than 20 samples acquired by use of traditional formation testers by Schlumberger and another service company, all were determined to be nonrepresentative. They were too contaminated to yield PVT properties during laboratory analysis. Mud-filtrate contamination can be assessed downhole by the live-fluid analyzer (LFA) in real time before fluid samples are collected. For example, at one sampling station in Well Bhagyam-4, LFA analysis quantified a 36% contamination—even after pumping for 105 minutes. Consequently, until recently, only simulated PVT data from mathematically corrected samples could be used for Bhagyam field development studies.