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Quarterly Journal of the Directorate General of Hydrocarbons(Under Ministry of Petroleum & Natural Gas)

ForewordV.K. Sibal

Rig Sharing: Bridging the Gap Between Supply and DemandIan Garrard .............................................................................................................................. 1-4

Floating Production Systems (FPS) Hull Selection ConsiderationsJohn Murray, Terje Eilertsen, Chris Barton .............................................................................. 5-6

Have We Discovered All The Oil In Upper Assam Basin?N. Mathur .............................................................................................................................. 7-12

Hydrocarbon prospects of selected Proterozoic Basins of IndiaC. Vishnu Vardhan, Smitha K. Panicker and B. Kumar ....................................................... 13-21

Methodolgy (ies) To Identify The Hydrocarbon Prospectivity Of The FracturedReservoirs In Indian Sedimentary Basins

GSSN Murthy and Amitava Roy ....................................................................................... 22-26

Basement Configuration of Indian East Coast on Either side of 850E RidgeJayanta Phukan, Amitava Roy & Samiksha ........................................................................ 27-29

Vol.-I April, 2007 No. 3

CONTENTS

It would not be an exaggeration to say that we areexploring for oil and gas in a resource-constrained era.In the oil and gas industry, the most common perceptionhas been that of dwindling resources of oil and gas. Inother words, limited supply of hydrocarbons has driventhe industry. The need for fossil fuel energy, and theburgeoning cost of this resource has transformed thisconstraint into a challenge. And in the process ofovercoming this challenge, we have spawned a wholenew genre of challenges. This includes serious resourceconstraints in terms of manpower and services. In thecurrent issue of the DGH journal Petroview, I would liketo share some of my thoughts on these important topicswith you.

The increase in global oil prices has given rise to a surgein demand for the rigs, drilling equipments & services,affecting the availability of these resources. The impactof this is also being felt in the E&P sector in India wheremassive exploration programs are underway by severalleading oil companies. Considering the present pace ofexploration, it is expected that in future, the shortagesfor equipment & services will multiply several fold.

In order to over come the above problem, sharing ofavailable resources viz. drilling rigs, related services,survey vessels etc. between the E&P operators in Indiais considered as a viable and pragmatic approach. Thisconcept is already being successfully implemented incountries like Norway, U.K. Mexico etc. The mostattractive feature of this concept is the hiring of serviceson a long-term basis that assures the availability besidesreducing the cost by means of sharing mobilization/

demobilization charges, idle time and negotiable reducedday rate charges. Further, it will also help in sharingtechnical information, skilled technical manpower andexpertise between E&P companies.

Directorate General of Hydrocarbons (DGH) hasinitiated the process for introduction and implementationof this concept in India. As a first step in this direction,DGH has planned to implement the Rig sharing betweenvarious E&P operators working in India in differentbasins.

A consortium comprising of 10 E&P companies has beenformed under the patronage of DGH to steer the Rigsharing concept. The consortium engaged M/s RigManagement Norway, AS (RMNAS) to carryout acomplete study on the demand and supply scenario forvarious types of drilling rigs in India. RMNAS is pioneerin implementing the rig-sharing concept and hassuccessfully implemented it in various parts of worldincluding U.K, Norway, and Mexico. Depending uponthe requirement, it is also planned to extend thiscooperation to other areas of E&P activities like drillingand survey related services in future.

RMNAS officials visited several Indian E&P operatorsand carried out a detailed study regarding the futuredrilling programme, requirement of rigs, etc. The conceptwas discussed at length with E&P operators duringRMNAS visit to their work centers. Keeping in viewthe tight rig market worldwide, timely execution of thecooperation is necessary in order to contract the availablerigs on top most priority. DGH advised the E&Poperators to expeditiously form region wise pilot groupsfor cooperation in different regions, both offshore andonshore.

Benefit of sharing the resources was clearly brought outby RMNAS in their presentation by illustrating theexample for contracting deepwater rig for 5 years inplace of 3 years would save rig day rate by up to US$55,000 accounting to US$ 83 Million over the contractperiod per rig. Substantial savings can be made inmobilization and demobilization cost also. Overallsavings may run into millions of dollars. The cost benefitto individual operator can be illustrated from the factthat by paying only US$ 21000 towards phase-I studiescost, the operators could reap-out the benefit of the entirestudy, thus a saving of US$ 190,000 per operator. If aventure of such a small magnitude could result in morethan 90% savings, it is obvious that operations in biggerscale have a lot to offer.

Foreword

V.K. Sibal, Director GeneralDirectorate General of Hydrocarbons

Another important issue that needs to be addressedrelates to the shortage of skilled and qualified manpowerrequired by the upstream sector. With the increase inexploration activity, there has been a commensurate needfor technically qualified and experienced manpower inthe industry. However, it has become increasinglydifficult to fulfill the gap between demand and supply.DGH has taken a small but significant step in thisdirection. To begin with, DGH has been recruiting traineeofficers, primarily in the Geology, Geophysics andReservoir Engineering disciplines from variousuniversities since the year 2005. Fresh postgraduatesfrom various reputed academic institutions undergorigorous training on various facets of E & P activity.Besides training within DGH, they are also sent onassignments to seismic survey vessels, onland andairborne geophysical surveys and other field visits. Itgives me great satisfaction to inform you that theresponse from the various E & P companies, both Indianand foreign, has been overwhelming. Majority of the

officers who have been trained in DGH have beenabsorbed by the industry and they are now well placedto face the technical and technological challenges of thepresent and future. DGH is continuing with the processof recruiting bright, young trainee officers and equippingthem with all the technical excellence needed to carryforward the golden era of petroleum exploration in thecountry.

Considering the above facts, it is my firm belief thatrather than creating new resources that may eventuallycause a glut in the market, there is a need for sharingresources optimally to overcome the problem ofshortages, reduce costs and keep up the tempo of oil andgas exploration in the country.

V.K.Sibal

1The demand for rig capacity has been fuelled by recenthighs in the oil price. E&P companies, including anincreasing number of the smaller independent operators,are striving to bring production on as quickly as possible.The larger oil companies with significant drilling programare securing rig capacity into 2009 and well beyond underlong term contracts, for upto 5 years. Drilling rates haveon average almost doubled in the last 18 months andrates for deepwater rigs/drillships are rumored to havebroken the US$ 500,000.00 per day barrier. The industryperception is that the level of investment in rig anddrillship new building is sustainable in the longer term;and that even with the increased capacity coming onstream a significant shortfall against demand isanticipated. Rig utilization is at its highest for many years.

Against this background, E&P companies with a morelimited drilling program and the smaller independent oilcompanies face frustrating times. In todays very tightdrilling market, they cannot be certain of securing a rigon competitive terms, or of securing a rig at all. Theconcept of rig sharing, therefore, is being more widelyexamined with increased interest. Other alternatives arealso being explored, with E&P companies consideringwhether to acquire and operate their own rig throughjoint ventures with contractor or farm out a participatinginterest in the field to contractors to secure a rig.

Rig sharing is still relatively uncommon, but anincreasingly attractive option. Its purpose is to enablesmaller, less financially strong E&P companies to clubtogether to secure drilling capacity. It also serves toenable larger E&P companies who have a limited numberof wells to drill to share costs (principally mobilizationand de-mobilization costs) and obtain a longer-termcontract at lower rates. The flexibility of rig sharing isalso potentially very attractive, and it need not be limitedto one specific area of operation provided the economicsadd up.

Contractors in the current market are looking at one yearminimum terms, with the expectation that they may beable to amortize as much as 50% of their upgrade/refurbishment costs over one year. If two or moreoperators can string together a sequence of drillingprograms, they can offer a more attractive contract termto contractors and seek to encourage a competitiveelement to their rig selection, which may otherwise belacking on a shorter term arrangement. However, it has

also to be recognized that there is very little history ofoffshore ventures cooperating with each other in themanner envisaged by a rig sharing agreement. Partneringarrangements under which offshore contractors agreeto collaborate for the benefit of a specific E&P projecthave, of course, attracted interest, particularly in theNorth Sea, but these are normally between companieswho are not in competition with each other and the risk/reward structure, often imposed upon the contractorsby a single, substantial oilfield operator, is very differentfrom that involving the sharing of a third party rig.

Consortium Approach to Rig SharingRig sharing involves a pooling by E&P companies oftheir requirements and the planning of a joint strategy.Time invested in planning will rarely be time wasted,particularly in this context. To the extent that the area ofoperations for each operator is one region, under oneform of regulatory control with comparable water depthsand subsea, wave and weather conditions, there shouldbe sufficient synergies to derive costs savings and otherbenefits from a rig sharing arrangement. If the area ofoperations within the operator consortium spans differentregions and regulatory controls, the issues becomemarkedly more complicated and the economics of thearrangements will become harder for those operators inthe more benign and less regulated environment tojustify- in effect, they may be subsidizing the higher costsof a more extensive rig upgrade or refurbishmentre1quired for the harsher and more regulated environmentof their consortium members.

There is a philosophical issue at the outset whenestablishing any consortium. The operators are notforming their alliance with a view of profiting from aventure they support and would otherwise tackle alone;they are taking a pragmatic step in response to the marketconditions, to save time and costs, but principally tosecure a rig. There are a numbers of risks inherent inthis. If one operators drilling program takes longer tocomplete through no fault of the contractor, this mayhave a material effect on the next operators program insequence. Absent recourse to the contractor, to theoperators look to apportion blame between theconsortium or not? The operators may be willing to adopta flexible, conciliatory approach to the arrangement andagree to absorb any loss each suffers (sort of any loss,

Rig Sharing Bridging the Gap Between Supply andDemand

Ian GarrardCurtis Davis Garrard LLP, UK.e-mail:ian.garrard@cdg.co.uk

2caused by willful misconduct or gross negligence onpart of another operator) or they may prefer to be moreprescriptive, setting out in detail the remedies that willapply in the event of any delays etc. The strength of therelationship between the consortium members willinfluence which approach is adopted but any attempt tobe too prescriptive runs the risk of becomingcounterproductive. It is also necessary to keep in mindthat the costs of establishing the consortium anddocumenting the agreements should be proportionateto the savings to be derived from the arrangement.

SecurityAt substantial day rates, even over a year, the questionof security will be an issue for the smaller independents.The contractor (and its financiers) will look for aguarantee of payment and one of the challenges for theconsortium of operators will be how they collectivelysatisfy the contractor that they have the resources topay and can provide security for payment. This raises asignificant timing issue. The consortium will need tosecure the drilling capacity well in advance of the windowallowed for drilling to commence. If they are unable tosatisfy the contractors requirement to secure payment,a contractor is unlikely to take a rig off the market and itis likely that the rig will be contracted elsewhere. In suchcircumstances, some form of adhoc arrangement may berequired, but achieving agreement on terms which secureexclusively over a rig for any extended period in thecurrent market is a real challenge. Contractors are notwilling to provide option in this market.

The Drilling Program, Rig Capability and form ofDrilling ContractClearly, agreeing the drilling program sequence betweenoperator is the key, and this will be influenced by theextent to which each program has been advanced andwhether all of the data required is available. A sufficientwindow will need to be allowed for each well in turn,bearing in mind not only the specific contingencies ofeach operators exploration program but also the inherentrisk of cumulative delay and rig movements between theoperators fields.

If one of the operators has a significantly longer drillingprogram than the other operators and the overallsequence is not reasonably balanced, the arrangementmay not be workable without significant flexibility onthe part of the other operators.In particular,if the firstoperator in sequence has a significantly greater numberof wells to drill, the risk of delay in completing thosewells is greater, with the other operators bearing the riskand consequences of any delay.

Consideration will also need to be given within theschedule to the number of optional wells, and whether

the arrangement can accommodate them for one or moreof the operators.

A common specification or the rig that accommodateseach of the operators requirements and the regulatoryregime will also need to be agreed at an early stage.

The operators will also need to agree on one set of drillingterms and conditions. Whilst this is self evident, thedifficulties should not be underestimated. They will alsoneed to agree on a contracting strategy for securing therig. The arrangement will need to be clearly presented tocontractors, who will perceive potential difficulties inserving more than one client, particularly if any problemsare encountered. Contractors will be especiallyconcerned to ensure that the invoicing and paymentprovisions are clear , so it is clear who they will haverecourse to for payment throughout the contract.

Transferring the Rig

So, what will be the legal mechanics of transferring therig from one operator to the next? The drilling contractcould be assigned from one operator to the nextoperator in turn. In the rig sharing context, this might beaffected by a novation rather than an assignment suchthat each operator assumes the right to call for the drillingservices to complete its wells and responsibility forpaying the applicable day rates during that period. Eachoperator would not assume any rights or liabilitiesrelating to any period during which drilling services werebeing provided to another operator. The parties wouldneed to agree the time and date on which he handoverform one operator to the next operator would take place,so that there was certainty to the transfer of rights/obligations. From the contractors perspective, it will lookto the consortium representative to notify it of therelevant time/date- it will not wish to become involved inany dispute between operators. Outside the drillingperiods, the consortium will need to agree which operatorhas carriage of the drilling contract, during anyupgrade/refurbishment of the rig and mobilization, priorto commencement of drilling services at the first well ;and equally in the period after completion of the last welluntil completion of demobilization.

The Rig Sharing AgreementThe rig sharing activity will normally be governed by anagreement between the operators who will be part of theconsortium. This rig sharing agreement will set out theprinciples for the sharing of the rig and supportingservices, with such costs/risks apportionment as theparties agree. It is likely to take several weeks to negotiateand agree upon a rig sharing agreement. It is thereforesensible to agree a short MOU setting out the principalfeatures of the arrangement, in part to determine whetherthere genuinely is a consensus on how the arrangement

3will operate, and also set out a general framework formoving forward.

Within the consortium, a number of contractual issueswill need to be addressed so that the parties intentionsare clear. What follows is a checklist of some of the issuesto be considered, in addition to the usual contractualterms.

Consortium Representative (s)Which of the operators will represent the consortium intheir dealings with the contractor? Whilst each operatorwill designate its own representative for the purpose ofits own drilling program, there are a number ofadministrative tasks relating to the rig sharing (includingthe preparation and issuance of an invitation to bid(ITB) and form of drilling contract; mobilization, logisticsgeneric to the contract as a whole, de-mobilization). Theoperators will probably need to acknowledge that therewill be no recourse to the consortium representativearising from the performance of its role, unless throughwillful misconduct or gross negligence.

ChangesIf at the time of securing a rig the drilling requirementsof each operator are not fully foreseen and changes arerequired to be made during the upgrade/ refurbishment

of the rig, how are the additional costs of those changes,to the extent that the day rate is adjusted, to be borne?Despite being paid through the day rate mechanism tothe contractor, are they to be re-allocated to the operatorwho sought the change? Each operators consent toany change will be required, because any changes mayhave a material impact on its drilling program. The timespent in planning is important for this reason, becausean operator alone will be unable to force through anychange.

Withdrawal rightsWhen, if at all, can an operator withdraw from theconsortium and what are the consequences? Theposition is likely to be different, depending upon whethera firm drilling contract has been concluded or whetherthe rig selection process is at an earlier stage. In eithercase, the drilling program sequence will need to beadjusted, but in the former case there is likely to be losttime in respect of which the contractor will expectpayment of the operating or stand-by rate. It would besensible to seek to agree in advance what the fee forwithdrawal will be, so that there is certainty.

Termination/ Suspension RightsIn the event that issues in relation to the contractorsperformance arise, the operator for whom the servicesare being undertaken at the time ought to be able to takecertain steps to enforce performance, but in large measurethis will be dealt with through the compensation regimeand the application of a zero rate or other applicable ratefor downtime. The other operators whose drillingprograms are next in line have a vested interest in ensuringproper performance by the contractor, but they will notbe willing to countenance a situation in which the rigcontract is suspended or terminated without theiragreement. It is, therefore, important that certain barelimitations on the exercise of such rights and the needfor consultation are included in the rig sharingagreement. Equally, there may be good reason to deferthe enforcement of certain remedies against thecontractor until the overall drilling program is complete.If the consortium comprises a number of smallerindependents with limited financial resources, theagreement (which looks to drilling services beingperformed 18 months or more ahead)ought also toaddress the consequences of the insolvency of anoperator, and how the remaining operators can protectthe drilling contract by qualifying the contractors rightto terminate in such circumstances, (if a new operator isbrought in or additional security is provided).

Cost SharingWhilst each operator will pay the day rate (s) applicableto drilling its wells, how will the generic costs such as

4the mobilization and de-mobilization fees andadministrative costs be paid and borne? Should they beborne equally or be borne in proportion to the numberof wells or program days of each operator? These arepurely commercial issues for the operators concerned;but some principles need to be established at the outset.An appropriate budget in relation to the consortiumrepresentatives activities on behalf of the consortiumshould be pre-approved, with the usual mechanisms forits revision on a periodic basis.

Delays

The philosophy adopted by the parties to thearrangement as a whole will dictate how delays to thedrilling program are handled within the agreement. Thesuccess of the arrangement depends upon there beingminimal delay such that the drilling programs for allParties are performed on time. There may be a number ofcauses of delay. If it is due to the contractors breach,the affected operator or consortium representative onbehalf of the consortium will have such rights of recourseas are agreed under the rig contract. Absent any recourseto the contractor, the delay may be due to an operatorslack of readiness or failure to plan adequately orunforeseen events may occur which could not have beenanticipated. The parties intentions should be expresslyset out and, if one operator is to have recourse to anotheroperator, specific remedies should be agreed, to avoidthe cost and time of resolving difficult issues of loss.

Step in rightA rationale for forming the consortium is collectivebenefit- safety in numbers-with the underlyingmotivation to maximize individual gain. But what if anindividual operator does not perform its obligations inother words, the primary obligation to pay the contractor?What if this happens during the first drilling program? Astep in mechanism is a sensible inclusion to protect theoperators next in turn. It is in the interest of all theoperators that the drilling contract remains on foot evenif one operator has unforeseen difficulties.

Operational logisticsOngoing communication between the operators and thecontractor is critical. Over the term of the drilling contract,there are a number of transfers or handovers of personnel,equipment and consumables. The potential for frictionamongst operators and between the operators and thecontractor will be dramatically reduced if they are allkept regularly informed.

The rig sharing concept may still be novel and it is informative stages but, for the foreseeable future in theprevailing market, it will continue to rapidly evolve as anattractive alternative for both small and larger E&Pcompanies.

Ian Garrard is a Partner at CDGand leads the offshore team

Ian.garrard@cdg.co.uk

5Introduction

Selection of a particular floating hull type can dependon a number of factors. For instance, the primary reasonsthat Operators select a Dry Tree Unit (DTU) are for wellintervention and riser response. Well intervention costscan represent 40-50% of OPEX. These costs can besignificantly reduced by selecting a dry tree approachand using a workover rig or drilling rig for wellintervention. Waiting on the availability of a MobileOffshore Drilling Unit (MODU) for well intervention cangreatly increase the well downtime. DTUs provide theopportunity to re-enter a well at any time. Some claimthat as much as 25% additional reserves can be recoveredusing dry trees vs wet trees.

Whether the hull type is a Spar, TLP or Semi, efficientdesign of floating structures is predicated onfunctionality and performance. It should be capable ofsupporting the necessary equipment for drilling andproduction, while at the same time meeting allperformance and safety-related criteria. The floatingstructure should provide sufficient space androbustness to fulfill its intended purpose and it shouldbe built at a minimum of cost, which is governed mainlyby the hull steel weight.

Hull SelectionSelecting a hull form is guided by criteria such asoperating environment, subsurface characteristics,availability of fabrication facilities, suitability to theoperators development plan, and sometimes anOperators preference for a certain concept.

Hull weight estimates are based on global sizing whichis determined by the naval architectural and structuraldesign. Global sizing is a key engineering process inboth the concept selection and follow-on design phaseof a floating structure. The sizing of a moored floatingstructure considers relationships between payload, hullsize, and mooring system. During concept selection,efforts are concentrated on the main dimensions andweights with respect to design standards andperformance requirements without a high degree ofengineering detail. Final dimensions and properties ofthe hull will be determined in the FEED stage throughvarious analyses.

Well and completion design are governed by thesubsurface characteristics. Designing a fit-for-purpose

floater takes into consideration whether it will supportdry or wet trees, future expandability, and its function asa production hub or wellhead platform. Some of thephysical considerations taken into account whenselecting a floater are hull steel weights in relation tosupported payload, the overall performance in aparticular environment (which has a direct impact ontensioning systems if a dry tree unit is selected), andmarine operations required for installation, and hook-upand commissioning.

Certain considerations influence the selection of adeepwater floating production system:

a. Small in-place motions to enable dry tree productionand drilling risers. The economics of a DTU - particularlyin view of present-day availability and cost of deepwaterMobile Offshore Drilling Units (MODUs) can be veryfavorable for systems that can drill and complete wellsfrom the same platform. Both the TLP and Spar have drytree capability.

b. Large, open deck areas to enable more efficientoperations. This allows for good ventilation, lay-downareas, and equipment arrangements on a single-deckelevation. The Semi and TLP are more adaptable to largefootprints and open areas. Because of the single caissonfootprint architecture of the Spar hull, the topsidesequipment has to be stacked several decks high.

c. Quayside integration to enable installation andcommissioning of topsides on the floating hull at aquayside location. This reduces cost and mitigates riskassociated with offshore operations since it eliminatesthe need for heavy-lift equipment. Quayside integrationrequires a floater to have adequate stability at a shallowdraft. The Semi and TLP have an advantage over theSpar in this regard.

d. Water depth sensitivity to enable a range of waterdepths given the additional buoyancy requirementsrelated to increased mooring and riser loads as waterdepth increases. The Spar and Semi are less sensitive towater depth, whereas the current limit for TLP technologyis around 5,000 ft, governed mainly by the tendons.

Spar TechnologyThe first Spars were based on the Classic caissondesign. This evolved into the Truss Spar by replacingthe lower section of the caisson hull with a truss. Sparsare ideal as DTUs because of their small vertical motions.

Floating Production Systems (FPS) Hull SelectionConsiderations*

John Murray, Terje Eilertsen, Chris Barton FloaTEC, LLC

6Dry trees provide direct vertical access to the wells,which allows the Spar to be configured for full drilling,workover, production, or any combination thereof. Oneof the distinctions of the Spar is that its center of gravity(CG) is always lower than the center of buoyancy (CB),hence it is unconditionally stable. The Spar derives nostability from its mooring system, so it does not list orcapsize even when completely disconnected from itsmooring. The deep draft is a favorable attribute forminimizing heave motions - its draft and large inertia filterwave frequency motions in all but the largest storms.The natural period in heave and pitch are above the rangeof wave energy periods. The long response periods forSpars mitigate the mooring and riser dynamic responses,which are common to ship-shaped FPSOs and Semis.The deep draft, along with the protected center well,also significantly reduces the current and wave loadingon the riser system. These loads normally control thetension and fatigue requirements of the production riserson TLPs.

The Truss Spar is characterized by a hard tankcompartmentalized to house void tanks and variableballast tanks, a truss section with a number of heaveplates, and a soft tank at the keel to hold fixed ballast.The hard tank is designed to provide sufficientbuoyancy to support the topsides, hull structure, andmoorings. The heave plates provide added mass anddamping, which gives the Spar a heave natural period

around 30 seconds. The water plane area inertia makes asmall contribution to the GM, which is controlledprimarily by the distance between the CB and CG. TheCG is kept low by installing fixed ballast in the soft tank.The Spar is moored using a spread centenary system,which is generally pre-installed before the hull arrives.

The main design features of the Spar are:

High heave and pitch natural periods greater than25 seconds (without risers)

Maximum offset of 7-9% of water depth in damagedcondition

Maximum heel angle less than 10 in intact anddamaged condition

Wet tow draft shallow enough to offload hull fromdry transport vessel

Adequate structural strength for up-righting duringinstallation

Buoyancy cans typically support the risers in wetcenterwells. New designs emerging use hydro-pneumatictensioners. When these are used, the weights of therisers are borne by the buoyancy in the hull. As thenumber of risers increases, the tensioners increase theheave stiffness of the Spar, which reduces the heavenatural period. The total tensioner stiffness is designedto have a heave period that is high enough above thewave periods to avoid resonance excitation. Buoyancycans in the open centerwell do not effect the heave period.However, buoyancy cans are difficult to install once thetopsides are in place. Buoyancy cans are installed beforethe topsides, whereas hydro-pneumatic tensioners canbe installed as the wells are tied back and completed.

SummaryIn summary, a general description of criteria for selectinga particular hull form are qualitative and based on anumber of general considerations evaluated in theselection process. The capacity of the three hull formsto satisfy these criteria is summarized in the Table below.

Small in-place motions

Large open deck areas

Dockside HUC oftopsides

Water depthinsensitivity

Minimum at-seacommissioning

Redeployment

Small motions, can supportTTRs and SCRs, accelerationsat deck level higher thanETLP and Dry Tree Semi

Because of small footprintfrom single column hard tankdeck is multi level

Because of deep draft. Sparmust be towed horizontally tothe installation site.

Covers a wide range ofdepths and payloads

Requires heavy lift vessel forsingle or multiple module lifts

Within limited water depths,sufficient to tow hull invertical orientation

Topsides can be installedand commissioneddockside

Small motions, cansupport TTRs andS C R s

Spar ETLP Dry-Tree Semi

Can be returned todockside for refit andredeployment

Can be installed onpreset moorings

Covers a wide range ofdepths and payloads

Topsides can be installedand commissioneddockside with heave plateretracted

Can support large opendeck areas similar toconventionalSemisubmersible

Difficult to disconnectfrom tendons

Requires installation onpre-installed tendons,can be difficult whereswell persists

Limited to water depth ofabout 6,000 ft withstandard tendon design

Can support large opendeck areas, steel savingsin smaller deck span

Small motions, cansupport TTRs andSCRs, can requirecentenary mooring toassist in offset control

*The article has been suitably edited to exclude commercial aspects of the products.

7Abstract

The Upper Assam basin has a history of producing oilfrom different formations, like Girujan (Upper to MiddleMiocene), Tipam (Lower Miocene), Barail (Oligocene),Lakadong member of Sylhet Limestone & Langpar(Eocene), for more than a century. A number of potentialsource rocks have also been identified in the basin thatinclude Barail coals, Barail shales, Kopili shales,Lakadong shales and Langpar shales. Coals are knownto be good source of oil. Huge reserves of coal belongingto Barail Group are present in Upper Assam. So thequestion arises, are the oils in Upper Assam basinsourced from coals? This article is based on acomprehensive study of the coals of Upper Assam basinwith the aim to determine whether they are capable ofgenerating oil and whether the oils present in the basinhave actually generated from them. The study showsthat Barail coals are oil prone and mature and thus capableof generating oil. Oil to source correlation study showsthat most of the oils from Upper Assam basin do notbeen correlate Barail coals. Only Tipam oils from Digboioilfield, which form a very small part of the total oildiscovered in the Assam basin, correlate with Barail coals.Thus, a huge reserve of mature, oil-prone Barail coal ispresent in the basin, which is likely to have generatedsignificant amount of oil. But most of the oil discoveredin the basin has not been generated from coals. It appearsthat a large amount of oil generated from Barail coals hasnot yet been discovered. Efforts should be made todiscover this oil.

Introduction

Correlation of oils with each other and with the sourcerocks plays a very important role in exploration in a basin.Oil to oil correlation helps to identify different families ofoils present in the basin. Since each family of oil musthave generated from a distinct source rock, oil to sourcerock correlation leads to identification of parent sourcerock of each family of oil. Once all the source rocks havebeen identified in a basin and oil to source rock correlationhas been done, it becomes easier to determine whetheran unexplored structure is likely to be oil-bearing or not.For example, farther a structure is from the sources of oil,less likely it is, to be oil-bearing. Further, mass balancecalculations can be done for each source rock todetermine the amount of hydrocarbons generated andavailable for accumulation. This can be compared withthe hydrocarbon reserves already discovered to

determine if still there are hydrocarbons present in thebasin that have not yet been discovered.

The Upper Assam basin in Northeast India has beenproducing hydrocarbons for more than a century. Oil isbeing produced from reservoirs in following formationsin Oil India Limiteds PEL area of Upper Assam basin

Girujan Formation (Upper to Middle Miocene),

Tipam Formation (Lower Miocene),

Barail Formation (Oligocene),

Lakadong member of Sylhet limestone Formation(Eocene),

Langpar Formation (Eocene)

Also, a number of potential source rocks have beenidentified. These include

Barail Group coals (Oligocene),

Barail shales (Oligocene),

Kopili shales (Eocene),

Lakadong shales (Eocene),

Langpar shales (Eocene)

Any of the above potential source rocks could be thesource of oils in Upper Assam basin. In this article (basedon Mathur, 2007) an attempt has been made to determineif the oils in Upper Assam basin have been generatedfrom Barail Group coals. This has been done first, byevaluating the Barail Group coals for their hydrocarbongeneration potential, oil-proneness and maturity andthen, correlating the coals with the oils from the basinusing biomarkers like C

30 triterpanes, oleananes,

bicadinanes and C29

steranes.

Hydrocarbon Generation Potential of CoalIt is now widely known that coals can act as a goodsource rock for oil. Huge reserves of Barail Group coalsare found in thrust-belt outcrop on the Northern flank ofNaga-Patkai Hills. The coals are known to be oil-prone(Sinha et al. 2005). It is likely that the coals have alsogenerated oil. In this study, seven Barail Group coalsamples were selected. Four surface samples belongedto Tirap, Tipong and Ledo coal mines located in theeastern part of Assam. Three sub-surface coal samplesbelonged to a well in Moran oilfield in OILs operationalarea. Coals were analyzed using Rock Eval 6 and

Have We Discovered All The Oil In Upper Assam Basin?N. Mathur, R & D Department, Oil India Limited, Duliajan 786 602 Assam

nmathur@oilindia.in

8Pyrolysis-Gas Chromatograph-Mass Spectrometer (Py-GC-MS).

Rock Eval analysis is useful to determine the organicrichness and quality of source rock. S

1 is a measure of

the bitumen present in the rock whereas S2 is a measure

of the hydrogen content and S3 is a measure of the

oxygen content of the rock. Tmax is a maturity parameterand Hydrogen Index (HI) and Oxygen Index (OI) arenormalized values of S

2 and S

3 with respect to total organic

carbon (TOC)

Table I shows the results of Rock Eval analysis of coalsamples. As is expected, coals have high TOC values (~50 80%). The S

2 values of the coals are very high (~ 100

270 mg/g) indicating that they have very goodhydrocarbon generation potential. A plot of HydrogenIndex (HI) and Tmax can give a very good idea about thequality of the source rock. Using this plot, the sourcerocks can be classified as Type I (oil prone), Type II (oil+ gas prone) and Type III (gas prone).

Figure 1 shows the HI-Tmax plot for the coals. Thesecoals are a mixture of Type II and Type III organic matter.Thus, they are capable of generating significant amountof oil apart from generating gas.

Py-GC-MS analysis of source rocks is used to find outthe type of hydrocarbons i.e. oil or gas that will begenerated when the rocks mature in the geologicalconditions. The result of Py-GC-MS analyses of a typicalBarail coal sample is shown in Figure 2. A series ofdoublets are seen in the chromatogram. Identificationusing mass spectrometer has confirmed that these peaksare n-alkane / alkene doublets. This confirms that thecoals are capable of generating oil.

Correlation of oils with Barail coalsFor the purpose of correlation, biomarkers have provedto be very useful. Biomarkers or biological markers arecomplex compounds present in oils and bitumens thatshow little or no change in their structure from parentorganic molecules in living organisms. Thus, if certain

Figure 1. HI vs Tmax plot for Barail coals

Table I: Rock Eval Data for sub-surface and surface Barail Group Coals

Sample Location Depth (m) S1 (mg/g) S2 (mg/g) S3 (mg/g) TOC (%) Tmax (C) HI (mg/g OI (mg/gTOC) TOC)

Well Moran A 3146 4.39 245.91 6.28 69.63 412 353 9

Well Moran A 3158 2.95 160.53 6.12 55.79 409 288 11

Well Moran A 3194 1.37 100.94 4.78 48.12 416 210 10

Ledo Mine Surface 4.26 238.38 3.64 73.17 421 326 5

Tipong Mine Surface 3.49 271.57 2.84 78.99 428 344 4

Tirap Mine A Surface 3.88 248.65 3.42 73.74 429 337 5

Tirap Mine B Surface 2.91 244.69 3.36 76.29 428 321 4

9Figure 2. Pyrolysis GC-MS (TIC) pattern of Barail coal

Figure 3. C30 triterpanes / hopane vs oleanane / hopane plot for oils and coals from Assam

biomarkers are present in a fixed ratio in oils as well asbitumens in the source rock, then one can conclude thatthese oils have derived from this source rock.

Seventeen crude oils belonging to different producingreservoirs were selected for the purpose of correlatingthem with Barail coals. The bitumen present in the coalswas also extracted. The oils and the extracts wereanalyzed using Gas Chromatograph with MassSpectrometer / Mass Spectrometer (GC-MS/MS).

Previous studies (Mathur, 2005) have shown that certainbiomarkers like C

30 triterpanes, oleananes and

bicadinanes are present in significant quantity in oils inUpper Assam basin. Moreover, biomarkers like steranesand hopanes are universally present in varying quantitiesin all the oils worldwide. Ratios C

30 triterpanes / hopane,

oleananes / hopane, bicadinanes / hopane and steranes/ hopane have proved to be useful for oil to oil and oilsource correlation in Upper Assam basin.

10

A plot of C30

triterpanes / hopane and oleananes / hopaneshows that oils in Upper Assam basin fall in two groups,I & II (Fig. 3). Group I oils belong to Eocene reservoirs.These oils are rich in both C

30 triterpanes and oleananes.

Oleananes are derived from land plants and are knownto be present in terrestrial oils that are younger thanCretaceous but generally of Tertiary age.

Similarly, C30

triterpanes have also been observed in many

terrestrial oils from Southeast Asia. Group II oils belongto reservoirs in Barail, Tipam and Girujan Formation. Theinteresting observation here is that coals are falling inGroup III, which is severely depleted in both C

30

triterpanes and oleananes. Thus, there exists a negativecorrelation between Assam coals and oils. Digboi oilfield,which is the oldest oilfield in India, has been producingoil from Tipam Formation. The Tipam oils from Digboi

Figure 4. Bicadinanes / hopane vs oleanane / hopane plot for oils and coals from Assam

Figure 5. Steranes / hopane vs oleanane / hopane plot for oils and coals from Assam

11

oilfield are correlating with the coals. Thus, it appearsthat most of the Assam oils have not generated fromcoals, except Tipam oils from Digboi oilfield.

Bicadinanes originate from Dammar resin and areobserved in terrestrial oils. Ratio of bicadinanes / hopaneis also a useful parameter for correlation of oils and sourcerocks. A plot of bicadinanes / hopane and oleananes /hopane (Fig. 4) also separates the oils in Upper Assambasin in to two groups. Group I corresponds to oils fromEocene reservoirs and Group II corresponds to oils fromreservoirs in Barail, Tipam and Girujan Formation. Assamcoals, as earlier, are falling in Group III. This confirms theobservation that these oils have not generated fromcoals. However, Tipam oils from Digboi oilfield arecorrelating with the coals.

Steranes are used as an indicator of marine input to theorganic matter from which the oil has generated. Highsteranes / hopane ratio in oil are indicative of marinenature. A plot of steranes / hopane and oleananes /hopane (Fig. 5) also separates the oils in to two groups.

Group I oils, from Eocene reservoirs, are low in steranesand high in oleananes indicative of their terrestrial nature.Group II oils from Barail, Tipam and Girujan Formationare richer in steranes have slight marine character. Assamcoals are falling in Group III and are low in both steranesand Oleananes. This shows that although the coals areterrestrial in nature, they have not formed from terrestrial

higher plants. Thus, these coals cannot be the sourcefor oils in Upper Assam basin.

A comparison of the results on the geochemical analysisof oils from ONGCs PEL area in Upper Assam (Goswamiet al. 2005) with the Barail coal shows that even the oilsin that part of the basin have not generated from coals.

Maturity of oils and coalsSterane maturity parameters C

29 S/(S+R) and C

29 i/(i+r)

(Fig. 6) show that oils are early to mid-mature. Sub-surface coals from a well are immature but the surfacecoals from the mines are mature. This is because thesecoals have been upthrusted from much deeper depths.Thus, the coals have attained sufficient maturity togenerate hydrocarbons.

ConclusionsThe study shows that huge reserves of oil prone andmature Barail Group coals in Upper Assam must havegenerated oil. However, most of the oil discovered so farin the Upper Assam basin has not generated from thesecoals. Thus, there is likelihood that huge amount of oilgenerated from Barail Group coals has not yet beendiscovered. Efforts should be intensified to discover thisoil.

Acknowledgement

The author is grateful to Management of Oil India Limitedfor permission to publish this article

Figure 6. Steranes maturity parameter plot for oils and coals from Assam

12

REFERENCES

Goswami, B.G. Bisht, R.S., Bhatnager, A.K., Kumar, D.,Pangtey, K.L., Mittal, A.K., Goel, J.P., Dutta, G.C. andThomas, N.J. (2005): Geochemical characterization andsource investigations of oils discovered in Khoraghat-Nambiar structures of the Assam-Arakan Basin, India.Organic Geochemistry, vol. 36, pp 161-181.

Mathur, N. (2007): Oligocene Coals as Possible Sourceof Oils in Upper Assam Basin. Petrotech 2007.

Mathur, N. (2005): Geochemistry of oils from EoceneFormation of Upper Assam Basin, India. Petrotech 2005.

Sinha, A.K., Prasad, I.V.S.V, Sharma, B.L., Gangu, J.,Goswami, B.G. and Mittal, A.K. (2005): Geochemicalevaluation of surface and subsurface Oligocene Barailcoals and coaly shales of Upper Assam shelf with respectto hydrocarbon generation. Petrotech 2005.

13

Abstract

The discovery of hydrocarbons from the Proterozoicformations of Russia, China, Australia, Oman etc. provedthat the older strata should not be omitted in theeverlasting search for petroleum. The Proterozoic basinsof India (Vindhyan, Chattisgarh, Cuddapah, Bastar,Kaladgi, Bhima) are comparable to the producing basinsof similar age from other parts of the world and haveall the necessary prerequisites for hydrocarbongeneration and accumulation. The Indian Proterozoicbasins have favorable structural geometry forhydrocarbon accumulation, rock types that can act asgood reservoirs and seals, rich stromatolitic and fossilassemblages, and presence of organic matter. Theevidence of hydrocarbon occurrences and gas showsare also reported from some of these basins. Thispaper presents an overview of hydrocarbon prospectsof selected Proterozoic basins of India based ongeological, tectonic, paleontolog- ical, geophysical andgeochemical information, and recommendations forfurther studies.

IntroductionTwenty-six sedimentary basins of India are classified intofour categories based on their hydrocarbon prospects.The basins that have established commercial productionare grouped under category I and category II has basinswith known accumulations of hydrocarbons but nocommercial production. The other basins, which aregeologically prospective, and potentially prospective,are grouped under Category III and IV basins,respectively. Six Proterozoic basins of India namelyVindhyan, Chattisgarh, Cuddapah, Bastar and Bhima -Kaladgi are grouped under category III and IV. Theoccurrence of commercial oil and gas accumulation inProterozoic basins of Russia, Australia, Oman and Chinahave proved that Proterozoic biomass was capable ofgenerating hydrocarbons. In Indian context hydrocarbonoccurrences in Proterozoic basins have been reportedby presence of gas shows from the test wells drilled inVindhyan basin1 and presence of bitumen and oil seepsfrom Cuddapah basin2. The other Proterozoic basins alsohave basic elements necessary for petroleum formation.

Geology and tectonics of Proterozoic Basins of India

The Proterozoic basins of India, called as Purana Basinsoffer favorable structural geometry for hydrocarbongeneration and accumulation viz. large open anticlines,buried domal structures, inversion structures, cross foldswhich are typical of giant oil fields3. Some of these basinsare least disturbed and unmetamorphosed withconsiderable sediment thickness. These basins also havesuitable geothermal gradient for hydrocarbon generationand maturation. The rocks which can act as goodreservoirs and seals, are also present in these basins.The geology and tectonics of some of the selectedProterozoic basins are discussed:

Vindhyan Basin

The Vindhyan is an intracratonic basin, having an arealextent of ~165000 sq.km. of which 65000 lies under theDeccan Trap volcanic flows (Fig. 1). The basin is limitedby son-Narmada lineament in south, Great BoundaryFault in west, Monghyr Saharsa Ridge in east4. Basedon the geophysical studies, it has been shown that thebasin extends underneath the gangetic alluvium towardsnorth in Ganga valley5. The sediments of the VindhyanSuper group attain a maximum thickness of about 5250 mclose to the southern margin of the basin1. Thesedimentary sequence of Vindhyan Supergroup has beendivided into two lithostratigraphic units, the Lower andthe Upper Vindhyans (Vindhyan Supergroup), separatedby a well-marked erosional unconformity (Table 1). LowerVindhyan consists of Semri Group and Upper Vindhyancomprises the Kaimur, Rewa and Bhander Groups.The lithology mainly includes limestones, shales,sandstones, conglomerate, siltstone and claydeposited in a shallow marine domain. The Vindhyansediments are least metamorphosed and considered asone of the best-preserved Proterozoic sedimentarysequence of India6.

The Basin has a characteristic rhombohedralconfiguration bounded by major faults and is dividedby Bundelkhand Massif into two parts, the ChambalValley in the west and the Son Valley in the east.

Hydrocarbon prospects of selected Proterozoic Basins ofIndia

C. Vishnu Vardhan, Smitha K. Panicker and B. Kumar*National Geophysical Research Institute, Hyderabad-500007

*e-mail: baleshk@yahoo.com

14

Table 1. General stratigraphy of Vindhyan basin

It generally dips southward, and the Lower Vindhyanrocks are comparatively more structurally deformed thanUpper Vindhyan. Normal faults (anticlinal structures) arereported along the son Narmada lineament arranged inan en-echelon pattern. There are many exposed foldsassociated with major fault systems, which are alignedin the direction of the adjoining faults. NW-SE trendingtight folds are reported around Chitaurgarh. Series ofstep faults are also reported along the southeasternboundary of Bundelkhand massif.

Chattisgarh BasinThe crescent shaped Chattisgarh basin is anintracratonic, middle Proterozoic basin located within thecentral Indian shield. This is the third largest Puranabasin of India covering an area of ~35,000 sq. km. Amaximum thickness of about 4000 m have been indicatedby Geophysical studies7. The Chattisgarh Supergrouphas an unconformable relationship with the Archeangranitic and gneissic basement. The supergroup isdivided into lower Chandarpur Group and upper RaipurGroup. The lithology includes conglomerate, siltstone,sandstone, limestones and minor amount of shales, claysand cherts8. The sedimentation is of cyclic nature startingwith limestone and ending with shale9 deposited in amarine environment. Stratigraphically, Chattisgarh basincan be correlated with Vindhyan and on the basis ofcyclicity in sedimentation it can be correlated withIndravati, Kurnool, and Bhima basins.

The basin slopes moderately towards west and it showscentripetal dips. In the eastern part, outliers of Gondwanaformations are noticed. Several outliers of Chattisgarhrock occur at different heights to the south and southeastdue to tectonism and denudation. The basin showsevidences of structural disturbances along the eastern,northern and western margins. In the eastern part thesediments are intensely folded and faulted. Srinivas etal.10, on the basis of gravity model had reported a ridgelike structure near Raipur where the thickness ofsediments is around 400 m. and on either side of theridge the thickness is about 2.5 km. The western andnorthern margins of the basin are also faulted, whereassouthern and southeastern margins do not show anysigns of disturbance.

Figure 1. Geological map of Vindhyan Basin (after Soni et al., 1987)

15

Cuddapah BasinThe Proterozoic Cuddapah basin (Figure 2) is anepicratonic basin covering an area of ~44500 sq.km. Theaggregate stratigraphic thickness is about 12000 m andthe sediments are deposited in a shallow marine carbonateshelf and beach environment11. The sediment thicknessincreases from west to east suggesting the deepeningof basin towards east. The sedimentary sequence ofCuddapah Super group is divided into lower PapagniGroup (2100 m), Chitravati Group (6000 m) NallamalaiGroup (3500 m) and younger Kurnool Group (520 m)comprising quartzites, limestone and shale units,

separated by an unconformity (Table 2). Each groupstarts with quartzite and ends with a shale unitrepresenting cyclic repetition of quartzite and shalesequence. This is reflective of transgression andregression in an episodically sinking basin. Theintrusives present in the basin are due to the igneousactivity that occurred simultaneously duringsedimentation and is thought to be a local phenomenon.All sediments in the basin are mature12 andunmetamorphosed except on the eastern part due to thethrusting of Eastern Ghat Mobile Belt.

The western half of the Cuddapah basin is less deformed

Figure 2. Geological map of Cuddapah basin (modified after Singh and Mishra, 2002)

16

as compared with the eastern part with sub horizontal orgentle quaquaversally dipping beds11. The general dipof beds in the basin is towards east. The rocks ofNallamalai Group are intensely folded, with intensityincreasing from west to east. In the intensely foldedeastern part, the Nallamalai fold belt, isoclinal folds areobserved and the eastern margin is intensely faultedand affected by thrusts. The Iswarkuppam, a N-Selongated dome is an important structural feature in thenorth-central part of the basin13. Faults in the basin aremostly steep, some are basement-rooted and pre-Cuddapah in age, and normal and reverse types arepresent whose periodic reactivation played a major rolein the evolution of Cuddapah basin.

Kaladgi BasinThe Kaladgi is a Mesoproterozoic epicratonic basincovering an area of ~8300 sq.km14. The basin has amaximum thickness of ~7000 m15 and deposition ofsediments is believed to be near shore shallow marinewith individual horizons indicative of lagoonal, beachand tidal environments. The sedimentation is cyclic innature due to the repeated marine transgression on anepisodically sinking epicratonic basin16. Some part ofthe northerly and westerly extension of the basin isconcealed under the Deccan traps and at places the trapsare removed by weathering and erosion. The rocks of

Kaladgi in these parts are exposed as inliers16. TheKaladgi Supergroup is divided into the lower BagalkotGroup and the upper Badami Group separated by anunconformity. The sedimentary sequence mainlyconsists of orthoquartzite, argillites and carbonatesincluding limestones and dolomite and sediments of thebasin are least affected by metamorphism except at thebasin margin. Dharwar Super group and Hungundschists, granites and gneisses form the basement for theKaladgis.

The Bagalkot group is much disturbed with tight isoclinalfolds, which can be contemporaneous withsedimentation where as Badami group suffered littledeformation. Sequences of the Lokapur Subgroup ofBagalkot group display doubly plunging synclinalstructure and elongated domal structures. These domesare surrounded by basins and vice versa. The SimikereSub group of Bagalkot group occurs as elongated doublyplunging synclines and, at places, with its complimentaryanticlines. The sequences of both the groups are cut byfaults and joints, the major faults being parallel to thedirection of regional axis.

Bhima basinThe Bhima basin is a neoproterozoic, epicratonic,extensional basin and is the smallest of all Proterozoicbasins of India. The NE-SW trending, S-shaped basin,formed due to gravity faulting17 has an area of ~5200sq.km. The geologically estimated maximum thickness isup to 273 m18 but gravity surveys revealed that a relief ofabout 10-15 mgals which can be interpreted in terms ofsediment thickness of approximately 1.5 km19. The Bhimahas independent sedimentation history compared toother Proterozoic basins of India20. The basement is theArchean Gneissic Complex and the top of the successionis covered by Deccan Trap flows and intertrappean beds.The Bhima Group comprises the Sedam and the Andolasubgroups separated by a paraconformity18. Thesediments include mainly shale, sandstone and limestonedeposited in a shallow marine domain.

The basin comprises tectonically least disturbed, nearlyhorizontal beds. The rectilinear E-W to NW-SE trendingboundaries are faulted, while the N-S and NNE-SSWlinear trends show unconformable relation with theunderlying gneisses. Among the faults, the E-W trendingGogi and Kirni dextral strike slip faults are extensive witha strike length of over 20 and 15 km. respectively17.Occasionally evidences of deformation like brecciationand slump folding due to movements along fault lines,which cut the basin, are observed. Signs of slightdisturbances prior to the outpouring of Deccan basaltsis indicated by the presence of broken and upturnedbeds. Except for the regions near faults where the bedsdip at high angles, original horizontal bedded character

Table 2. General stratigraphy of Cuddapah basin

17

is preserved (with dip rarely exceeding 5) for the Bhimasediments20.

Age

The Proterozoic sedimentary succession of India(Vindhyan, Chattisgarh Cuddapah, Kaladgi and Bhima)mostly range in age from Mesoproterozoic toNeoproterozoic. Based on biochronological data, thedeposition of Vindhyan sediments started around 1400Ma and had continued for over 800 Ma6. The studies ofMurti8 and Kruezer et al21 have suggested a Meso toNeo Proterozoic age for Chattisgarh basin. Thesedimentation in Cuddapah basin has begun at 1700 Ma22

and continued upto Neoproterozoic. The rocks belongingto Kurnool have been ascribed a Neoproterozoic age23.Cuddapah and Kaladgis can be correlated with Vindhyanand Chattisgarh based on faunal assemblage12. A closeresemblance in lithological characters of the rocks of theBhima Group with that of the Kurnool Group of CuddapahSupergroup has been noticed, suggesting that bothformed during Neoproterozoic20.

Palaeolife

It is widely accepted that the prime source forhydrocarbon generation is the marine phytoplankton.Vassoyevich and Sokolov24 confirmed that .thereare no grounds for doubt that phytoplankton was themain supplier of organic matter to the Precambriansediments. Laboratory studies have shown that underconditions designated to stimulate those occurring duringnatural geochemical maturation, modern algal matcommunities (stromatolites) can yield hydrocarbons25.Stromatolitic algae and bacteria are, therefore, amongthe potential sources capable of generating petroleumand consequently stromatolitic bearing Precambrian/Proterozoic carbonate rocks cannot be ignored in theever-lasting search for new hydrocarbon accumulations/resources26. The Proterozoic sediments of India are richin stromatolites and other organic matter and can beconsidered favorable for hydrocarbon generation andaccumulation.

The microbial life in Vindhyan sediments is representedby the well-preserved algal stromatolites, primitivebrachiopods, annelids and arthropod, planktonic,benthic microfossils, vascular plant remains, Chuaria sp.,acritarchs, algal and fungal remains etc.1,6 The limestoneformations of both Semri and Bhander Groups haveyielded abundant stromatolitic assemblages. About 50records of metaphytes and metazoa are reported fromVindhyan Supergroup. In Chattisgarh basin,stromatolites are reported from limestones of RaipurGroup27-29. The stromatolites show columnar, domal andstratiform morphology30. Murti31 has reported tracefossils, mainly metazoans from limestones and shales of

the Chattisgarh basin. Calcareous algae and burrowshave been recorded from the uppermost part of theRaipur sequence. In the upper part of the sedimentarysequence, presence of microbiota mainly filamentouscyanobacteria and acritarchs are reported32.

The sediments of the Cuddapah Basin have yielded richstromatolitic assemblages, Ediacaran fossils, sabellidites,chuaria etc. The Lower Cuddapah (Papagni andChitravati) carbonates show evidence of significantdevelopment of columnar stromatolites. The Vempalleformation of Papagni Group and Tadpatri Formation ofChitravati Group are characterized by the presence ofstromatolites demonstrating the extent of proliferationof microbial life during Cuddapah sedimentation33.Ediacaran fossils from Paniam quartzite of Kurnool group;sabellidites, and chuaria from Owk shale of Kurnool grouphave been reported by Gururaja et al. 34. In the southwestpart of the Cuddapah basin (Thummalapalle-Gandankipalle area) the shale contain thin stringers ofbrown colored organic matter (bitumen?) and humic acidproduced by decay of algal colonies2.

The occurrence of different species of stromatolites, algalsphaeromorphs, acritarchs, cellular tissues, oncholitesetc. indicate the presence of life during Kaladgisedimentation. Stromatolites occur in large coloniestermed as Stromatolitic bioherms in the limestone anddolomitic horizons indicating intense algal activity35. TheBagalkot Group of Kaladgi Supergroup have yieldedmicrofossils of algal sphaeromorphs, arcitarchs andcellular tissues with amorphous organic debris andKussiella, Collonella genus22. Badami group of rockscontains trace fossils, acritarchs and palynoassemblages. The Bhima rocks are characterised by arich assemblage of acritarchs, algal filaments and organicplates of possible animal origin36. Algal structures(stromatolites) and microplanktons are reported fromBhima Group of sediments by Gowda37 and Gupta23.Occurrence of Chuaria circularis38, rich and diversifiedvariety of biota, both mega and micro are reported fromthe Halkal shale of Sedam subgroup39.

Hydrocarbon Prospects

The Proterozoic basins of India have all the necessaryprerequisites for hydrocarbon generation, such assignificant sediment thickness, favorable structures,biological life, thermal gradient and are similar to theother producing basins of the world. The hydrocarbonprospects of selected Proterozoic basins of India arediscussed below:

Vindhyan BasinThe Vindhyan basin has considerable sediment thicknessupto a maximum of 5250 m. The geothermal gradient inthe basin is greater than 70 mW m-2 and based on that

18

the basin is categorized under medium to good prospectzone for hydrocarbon generation40. Limestone andsandstone sequences can form good reservoir rocks dueto the development of fracture and secondary porosities.Presence of lithological units, which can act as effectivecaprocks are reported by Chakrabarti5. In UpperVindhyans, cap rock conditions are better than in LowerVindhyans due to the presence of alternating shale,sandstone, and limestone sequences. The unconformitybetween Lower and Upper Vindhyans may act as a sealrock. The structures along the Son Narmada lineamentand series of step faults along the southeastern boundaryof Bundelkhand massif may act as favorable locales forhydrocarbon accumulation. Tectonically, Vindhyan basinis comparable to Proterozoic basins of Russia (LenaTunguska) and Australia (Amadeus), which areproducing. The geochemical studies of Vindhyanequivalent rocks from Ganga basin revealed theoccurrence of green colored amorphous organic matterwith algal filaments (type II kerogen) capable ofhydrocarbon generation. Considerable TOC content(upto 8.08% in Kajarahat Limestone, 6.43% in BijaigarhShale, 1.09% in carbonaceous shales) and organic carbondistribution (C

org. upto 1.76% in the limestone and shale

sequences in both Upper and Lower Vindhyans)suggests the development of potential source rocks inVindhyans1. The sediments show the organic maturitylevel well within wet to dry gas generation limit. Thewetness studies of absorbed C

1 to C

6 hydrocarbons

(20.77-97.11%) and the Thermal Alteration Index values(3.0 3.5) of the Vindhyan equivalent sediments in Gangabasin (Puranpur-2 well), show a maturity level within theactive oil and gas generation limit (oil window)1. Thesediments extending in the northern part below thealluvium can have better hydrocarbon generationpotential. Isotopic studies carried out by B. Kumar, etal.41,42 have shown that the carbonate rocks of the NagodFormation of the Bhander Group are characterized bymarked positive 13C signatures (4.10.9 0/

00 V-PDB)

suggesting higher organic productivity / burial. Thegently dipping Nagod Formation carbonates of BhanderGroup (Upper Vindhyan) are generally exposed on thesurface, however, if sufficient sediment cover overliesthese carbonates, as may be the case of Indo-Gangeticalluvial terrain, they can form good source rock forhydrocarbon generation. National Geophysical ResearchInstitute (NGRI) in association with Directorate Generalof Hydrocarbons (DGH) has carried out a reconnaissancesurvey for surface geochemical prospecting forhydrocarbons in the western part of Vindhyan basin(Chambal Valley) and reported that the region in andaround Baran-Jhalawar-Bhanpura-Garot may form a warmarea for future hydrocarbon exploration (UnpublishedTech. Rep. No. NGRI-2002-Exp-361). Krishnan43 recordedthat the lower Vindhyan shales have geochemical

parameters with possible source-rock potential.

All the above features confirm that Vindhyan sedimentshave necessary potential for hydrocarbon generationand entrapment. The reconnaissance surveys and someof the exploration wells drilled in Vindhyan Basin haveshown hydrocarbon generation/occurrence1,44.

Chattisgarh BasinThe maximum sedimentary thickness of the Chattisgarhsediments is about 4000m and sediments are depositedin a stable beach environment. The basin is having heatflow above100 mW m-2 and geothermally it is categorizedas a medium to high prospect zone40. In the eastern part,the sediments are intensely faulted especially in theBarapahar area. Rich assemblages of stromatolites arereported from limestones in Raipur Formation. Thecalcareous algae, cyanobacteria and acritarchs arerecorded from the Chattisgarh basin.

Although the Chattisgarh basin has all the prerequisitesfor the generation of hydrocarbon, like considerablesediment thickness and sufficient organic content, therecent surface geochemical studies (adsorbed soil gassurveys) carried out by NGRI and DGH have suggestedthat hydrocarbon generation has not taken place in thebasin (Unpublished Tech. Rep. No. NGRI-2004-Exp-456).

Cuddapah BasinThe aggregate thickness of Cuddapah sediments isabout 7000m. in the western part of the basin andthickness towards east in the basinal part is ~12 km. Thenorthwestern and southeastern regions of the basin haveheat flow over 130 mW m-2 and these regions areconsidered to associate with highly prospective zonefor the generation of hydrocarbons40. This is the thickestPurana basin of India. The thickness of the sedimentswhere the Nadyal shale (Upper Kurnool Group) isexposed, is in the range of 6000-9000 m and these shalesare considered as a future target for petroleumexploration2. The Vempalle limestone/dolomite can actas good reservoir rocks with its vuggy and fractureporosity. The Papagni and Chitravati Groups are mostlyundisturbed and have the prerequisites, which can befavorable for generation and accumulation ofhydrocarbons. The eastern margin of the basin(Nallamalai Group) is highly disturbed with isoclinal andrecumbent folds, complex faulting and also thrusting withthe Eastern Ghat Mobile Belt, however K. Chandra, etal.2 have shown that these form ideal sites to look for thetraps below the Nallamalai group of sediments. Thestructures like synclines, anticlines, fault closures etc.can play an important role in hydrocarbon generationand entrapment. The Vempalle limestone Formation ofPapagni Group and Tadpatri shales of Chitravati Groupcontain abundant stromatolites and can be potential

19

source rocks. Rich assemblages of ediacaran fossils,chuaria circularis, Sabellidites etc. have been reportedfrom the Kurnool group, which may have potentialhydrocarbon occurrences.

Adsorbed Soil Gas Surveys carried out by NGRI jointlywith DGH have shown that the basin has hydrocarbongeneration potential (Unpublished Tech. Rep. No. NGRI-2005-Exp-499).

Thick sedimentary succession, reported presence of life,suitable lithounits, structure and the geothermal gradientcan be favorable for hydrocarbon generation andaccumulation.

Kaladgi Basin

The aggregate thickness of the basin is about 3800 m.and further thickening is expected towards thenortheastern part. Based on geothermal criteria, the basinhas heat flow over 130 mW m-2 and is grouped underhigh prospect zone for hydrocarbons40. The fold patternsin limestone member of Yendigeri Formation and theUpper Badami group and domal and basinal structures;fault and joint patterns from both the groups may formgood structures for hydrocarbon generation andentrapment. The limestones and dolomites of bothBagalkot and Badami groups contain abundant fossilremains including acritarch, sphareomorphs, oncooidsand can form potential source rocks. Some part ofnortherly and westerly extension of the basin isconcealed under Deccan Traps, which might haveprovided sufficient thermal conditions for hydrocarbongeneration.

Necessary thermal conditions due to Deccan volcanicityand prerequisites such as thick sedimentary succession,fossils, lithounits and structure may be favorable forhydrocarbon generation.

Bhima Basin

The gravity surveys in Bhima basin show a thickness ofapproximately 1.5 km19. The Bhima basin is categorizedas high prospect zone for hydrocarbons based ongeothermal criteria, having heat flow over 130 mW m-2 40.The rich assemblages of algal structures (stromatolites),microplanktons, acritarchs, algal filaments and organicplates of possible animal origin, have been reported fromLower and Upper Bhima groups. A variety of biota, bothmega and micro also have been recorded from the Halkalshale. The Shahabad and Katamadevarhalli formationsare characterised by positive 13 C signatures (an averageof 2.4 o/

oo V-PDB for Shahabad and 2.7 o/

oo V-PDB for

Katamadevarhalli) indicating higher organic productivity

or burial during sedimentation, which may have bearingon hydrocarbon generation44. The top of the Bhimasuccession is covered by Deccan Trap flows and thatmight have provided sufficient thermal conditions forhydrocarbon generation.

The Bhima group of rocks have all the basic prerequisitesas shown above for generation of hydrocarbons.

Summary and recommendations

The geological, tectonic, paleontological, geochemicaland geophysical informations presented above suggestthat the Proterozoic basins of India may have necessarypre-requisites for hydrocarbon generation andaccumulation. The further studies needed to assess thehydrocarbon prospects of these basins are as follows.

i) Remote Sensing studies aided with digital imageprocessing in all the basins to delineate the surfaceand subsurface structural features.

ii) Detailed geophysical studies consisting of gravity,magneto telluric, seismic surveys in Bhima andKaladgi basins to determine the thickness of trapand the sediments.

iii) Reconnaissance geochemical surveys comprisingof adsorbed soil gas surveys for hydrocarbonexploration in the western margin (covering Papagniand Chitravati Groups) of Cuddapah Basin andKurnool sub-basin; northwestern part of Kaladgibasin (covering Badami Group); and in Bhima basinto demarcate anomalous hydrocarbon zones andwarm areas.

iv) Detailed adsorbed soil gas surveys (2 km X 2 kmgrid) for geochemical prospecting for hydrocarbonsin specific blocks in western Vindhyan basin (in andaround Baran-Jhalawar-Bhanpura-Garot),southeastern part of Bundelkhand Massif (SonValley) and along the southern margin of Vindhyanbasin.

v) Stable isotope studies of soil gases from Vindhyan,Cuddapah, Bhima and Kaladgi Basins to determinetheir provenance and source.

vi) Integrated geological, geochemical, geophysical andremote sensing studies to demarcate the potentialhydrocarbon zones.

Acknowledgement

The authors are thankful to Dr. V.P. Dimri, Director NGRIfor taking keen interest in this work and grantingpermission to publish this paper.

20

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IntroductionThe Exploration of Hydrocarbons has becomeincreasingly challenging as more and moreunconventional and unorthodox reservoirs are beingexplored with increasing uncertainities.The easy oil isalready explored.

Fractured reservoirs are an important component of theglobal hydrocarbon reserve and production base. In manyparts of the world, including USA, Canada, India, theMiddle East and Mexico, fractured reservoirs accountfor a part or the bulk of world oil production. In otherareas, such as the Rockies of North America, Assam-Arakan and part of Cambay Basin in India, lowpermeability formations that were once consideredunconventional hydrocarbon resources are now quicklybecoming mainstream.

In India, Oil production from fractured igneous/volcanicreservoir rocks and subsequent reserve replenishment

Methodolgy (ies) To Identify The HydrocarbonProspectivity Of The Fractured Reservoirs In Indian

Sedimentary BasinsGSSN Murthy and Amitava Roy

Directorate General of Hydrocarbons, New Delhie mail: ganti_murty2000@yahoo.co.in and aroy_amitav@yahoo.com

Assam Arakan Fold Belt Cambay Basin Mumbai High Basin Krishna-Godavari Basin Cauvery Basin

and accretion of OIIP are going on in the eastern andwestern onshore basins since last 25-30 years fromBorholla-Champang fields of Assam-Arakan fold Belt andPadra field of Cambay Basin

Besides the above sedimentary basins, India has got otherpotential basins to hold sizable hydrocarbon prospectsin fractured reservoirs of Precambrian, Proterozoic,Paleozoic, Mesozoic and Cenozoic rocks.

A Few Indian Basins to Look for Fractured Reservoirsare (Figure-1):I) Assam-Arakan fold Belt

ii) Cambay basin

iii) Mumbai Offshore Basin

iv) Krishna-Godavari Basin

v) Cauvery Basin

vi) Andaman Basin

Figure 1. Producing Indian Basins with Presence of Fractured Reservoirs

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Origin of FracturesThe fractures are developed in rocks due to the stressreleased because of seismic disturbances, basementfaulting, major lineament related tectonics. A basementreservoir is always associated with a high on which it isdirectly formed during the gradual uplift over geologictime. Sedimentary rocks which deposit later, overlie thebasement or come into juxtaposition due to subsequentfaulting and growth fault related tectonics. The magnitude,directions and sizes of fractures depend upon a fewfactors, including:

i) lithology of rocks

ii) compactness of rocks

iii) depth of burial

iv) Intensity of the earthquake

v) strength of the lineament

Classification of FracturesGeologically the fractures can be classified as:

Surface RelatedThese are not important from hydrocarbon point of viewsince most of the oil accumulated in these fractures mighthave been lost due to surface leakage.

Regional

If regional fractures are properly sealed then they becomeimportant for HC accumulation. It grades 2nd in theclassification scale of fracture porosity/HC accumulationand production.

ContractionSome amount of fracture porosity are developed ascontraction fractures and they are graded 3rd in theclassification scale for Hydrocarbon accumulation/saturation and production

TectonicFold or fault related and developed due to the unevenstress distribution. This kind of fractures entrap maximumhydrocarbon and maximum production is obtained fromthese tectonic fractures

Source, Entrapment, Reservoir and Seal ConditionsOften sedimentary rocks are the source rocks ofhydrocarbons which after generation, migrate laterallyto the adjacent naturally fractured basement or otherfractured reservoir rocks using the available faults, jointsor fracture systems as conduits for migration afterexpulsion from organic rocks during compaction. Mostof the time it is the technical basement or a basal sandstone or other sedimentary rocks derived from theweathering, erosion and diagenesis of the basement

which play the role of the reservoir. However, in afavourable geotectonic environment the fracturedbasement (igneous/metamorphic) with interconnectedfracture porosities can hold huge amount ofhydrocarbons in their fractures.

Indian Examples

Assam-Arakan fold Belt

The granitic/meta granitic fractured basement rocks aswell as the basal sandstone lying above it in Borholla -Champang fields of Assam-Arakan fold Belt are havinggood amount of produceable hydrocarbons .

Cambay BasinIn Padra field of Cambay Basin, 11 Km southwest ofBaroda, Oil is being produced from the fractured basaltand also from the immediately overlying Olpad Formationfrom several other fields of Cambay basin. Fractured coalof Motera and Kalol fields of Ahmedabad sub-block ofCambay Basin , produce oil & gas.

Cauvery BasinIn the Cauvery offshore basin, four productive gas wellsincluding the discovery well PY-1-1 in the PY-1 Field onthe Portonovo high (Anon,1995) reported13 MMCF/dayflow of gas (Anirbid Sircar,2004). from heterogeneous,Precambrian, weathered granite reservoir rock of about200 ft thickness and at depths of 5000 to 5500 ft. Thefield lies beneath approximately 250 ft of water depth.It was estimated that PY-1 could yield as much as 250BCF of gas and 1.16 M bbl of condensate in primaryproduction.

Mumbai High Basin

Occurrence of oil & gas in semi-commercial quantitiesin fractured basement was reported from Mumbai Highfield.

Krishna-Godavari BasinHydrocarbon occurrences in semi-commercial quantitieswas reported from fractured basement in Bantumilli andfrom fractured traps (basalt) in Mummidivaram in Krishna-Godavari Basin.

Exploration for Hydrocarbons in Fractured Reservoirsin Producing Basins of India:

An explorationist may take cue from this, that in thedifferent geological systems in India, hydrocarbonbearing fractured reservoirs exist and production of oil/gas is also going on on a commercial basis.Occurrence ofhydrocarbons in semi-commercial quantities in prolificallyproducing basins of India,should attract the attention ofthe explorationists to undertake a concerted explorationactivity for exploring hydrocarbons in fractured reservoirsin those basins.

24

Petrophysical and geological data, well log datainterpretation, and seismic modeling.

Well logs and borehole cuttings have been analyzed toascertain the geologic factors controlling horizontal andvertical rock density as well as the distribution of fracturesin the formation and the extent to which porositycontributes to hydrocarbon production in the field. Theseresults have been integrated with seismic data todetermine if the fractured intervals have a characteristicseismic signature.

High-resolution seismic data is required to delineate thefracture zones between wells in an oil field. SwRIconducted a feasibility study to determine whethercompressional (P) and shear (S) waves