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A numerical model of non-isothermal flow in pure carbon dioxide production or injection wells was developed. The model includes single or two-phase flow, heat transfer between the wellbore and its surroundings, and an accurate representation of the thermophysical properties of carbon dioxide, even near its critical point. Model predictions matched pressures measured during a field production test to within 30 psi and temperatures to within 3°F for flow rates between 4 and 22 MMscf/D. Sensitivities to wellhead conditions and flow rate for a pure carbon dioxide injector were examined with the model. Explanations of behavior during production and injection should improve our understanding of the use of carbon dioxide in the oil field.

Concessions were predominantly used up until the late 1960s, when Production Sharing Agreements- or also called Production Sharing Contracts (PSA or PSC) - came into existence. They provide an alternative to concessionary systems for those foreign countries, whose constitutions stipulate that all mineral rights lie with the state, but who do not wish to exploit their hydrocarbon resource base on their own. Regulations, which govern the external oil and gas reserves reporting, give a high degree of latitude as to how a company interprets and applies those rules to reserve bookings. From a financial point of view, PSAs and concessions are quite similar; they are distinctly different though from a philosophical point of view. The concession owner holds title to the hydrocarbons in place, whereas in the PSAs the entitlement is not transferred to the contracting party. But it is the entitlement to reserves, which ultimately provides the right to book reserves. For concessions, the reserve booking procedure is very clear, since the concession owner owns the mineral rights, whereas in case of PSAs the situation gets much more complicated. This paper explores different types of such agreements. It further discusses the question, whether reserve bookings for internal and external reporting purposes are permissible under certain kinds of arrangements and what, if any, volumes can be booked. Two methods are applied: The working interest method and the economic interest method. The hazard in using the working interest method, lies in the fact, that the government production entitlement would be treated as a tax expense from the contractor's point of view. But the host government or their representing oil institution will book their share of profit oil/gas as well, leading to reported gross reserves exceeding those ultimately produced. It would be preferable if oil companies strive to apply the economic method uniformly. The economic interest represents the actual barrel entitlement and thus is comparable to reserve numbers from concessions or leases. As the investment community places great significance on reported volumes to gauge the company's financial strength and future growth potential, it would be desirable to achieve a higher degree of consistency in reserve booking industry-wide. Internally the company will profit by improving benchmarking in portfolio management decisions.

Summary The Kuparuk River field on the Alaskan North Slope produces from twostratigraphically produces from two stratigraphically independent sands of the Kuparuk River formation. A full-field reservoir model was constructed tosupport field management and development planning. The model captures planning. The model captures essential aspects of two independent producing horizons, hydraulically producing horizons, hydraulically coupled at the wellbores, andsimulates dynamic interactions between the reservoir sands and surfacefacilities. The field model is used to plan field development on the basis ofperformance ranking of drillsite performance ranking of drillsite expansions, to assess depletion performance effects of reservoir performance effects ofreservoir management strategies, and to evaluate alternative depletionprocesses and associated reservoir and facility interactions of fieldprojects. Introduction A variety of development options are under evaluation for potentialimplementation at the Kuparuk River field. Several competing depletionmechanisms currently exist in the field. Introducing new projects will add tothe complex interrelationship of these depletion processes. Full-fieldreservoir simulation is used to forecast production performance under existingand future field performance under existing and future field configurations, toevaluate reservoir and facility interactions associated with field developmentalternatives, and to support ongoing field operation and management. This paperdiscusses the application of full-field paper discusses the application offull-field simulation to development planning and reservoir management at the Kuparuk River field. Motivation for Field-Scale Simulation. Using large-scale simulation forreservoir performance appraisal and development performance appraisal anddevelopment decision making has increased steadily* since the early developmentof black-oil reservoir simulators. Full-field reservoir simulation allowsreservoir depletion processes to he fully integrated with surface-facilityoperating constraints, resulting in resolution of dynamic interactions betweenthe reservoir and facilities. The need to quantify reservoir performanceexpectations more accurately spurs the development of more rigorous and complexfull-field reservoir models. Increased understanding and certainty derived fromadvanced field-scale simulation contributes to the decisionmaking process andpartially mitigates the risk associated with the large capital expendituresrequired for reservoir development. Kuparuk Reservoir Characteristics. The Kuparuk River field is located about40 miles [64 km] west of the Prudhoe Bay Unit (Fig. 1). Discovered in 1969, the Kuparuk reservoir contained an estimated 5 billion bbl of original oil in place(OOIP) with estimated recoverable reserves of nominally 1.6 billion bbl. The reservoir is made up of two distinct sandstone members within the Kuparuk River formation, a Lower Cretaceous, shallow, marine-shelf sanddeposit. The members are separated by a major unconformity, and two units arerecognized within each member. As Fig. 2 shows, the lower member contains Units A and B (informally named), with reservoir-quality sands present primarily in Unit A. The upper present primarily in Unit A. The upper member contains Units C and D, with reservoirquality sands present only in Unit C. Fig. 3 illustratesthe lateral extent of the Kuparuk sands. The A sand extends over the entirefield; the C sand covers a smaller area. Fig. 4 shows the dominant structural aspects of the Kuparuk sands. The Kuparuk interval forms a gently dipping anticline ranging in depth from 6,500to 8,500 ft across the structure. The trapping mechanism is a combination ofstratigraphic pinchout, erosional truncation, structural closure, pinchout, erosional truncation, structural closure, and a water/oil contact. Thereservoir is highly faulted by normal faults with up to several hundred feet ofthrow, which has a significant impact on flow unit continuity and fluidmovement. The predominant north/south fault trend density is nominally 3faults/sq mile. Faulting occurred during different depositional periods of the Kuparuk sands, influencing the character of the sand accumulations. Faultingoccurred primarily postdepositional to the A sand and postdepositional to the Asand and syndepositional with the C sand. Consequently, faulting frequency andpatterns are dissimilar for the two sand bodies. The Kuparuk sands are fairly thin, averaging 50 to 100 ft of grossthickness, but laterally extensive, covering roughly 200 sq miles. The C sandcontains several highly permeable, very prolific, interbedded zones permeable, very prolific, interbedded zones having an average permeability thickness of5,000 md-ft. Reservoir quality of the C sand, expressed by the distribution ofreservoir properties, is highly influenced by diagenesis and indirectly relatedto depositional facies. The A sand is characterized by sheet-like sandstonebodies interbedded with shales and mudstones. The A sand reservoir quality iscontrolled by depositional environment, and this sand, with its averagepermeability thickness of 1,000 md-ft, is permeability thickness of 1,000md-ft, is much less productive than the C sand. JPT P. 974

Copyt[ghl 1987, SC-ctety 01 Pelfoleum EngineersTh!s paper was prepared for presen!at,on al the Nmlh SPE .Symp+w.,um on 17eservG#l .%mufaf$on held m San Anmnto. Texas. February 1-4. 1987 ThIS paper was selected for pfesenlahon by an SPE Program Commdlee following rev!e* of !nformal,on conlamied m en aks',aclSubm!lfed by the aulhoqs) Contents of the paper. as pfeSented. have not been rewewecl by fhe %cjely of PfJl10L9um Engineers and a$e sublet! 10 Correcfxon by Ihe au fhor(a) Themalerlal. as presen fed. dOOS nol necessatiy rellec! any posmon 01 lhe SOC@ly of Petroleum Engineers, 11$OfflC.3rs, of members Papers pre;ented m SPE meelmgs are S.ub]ecf lr publcat!On rewew by Edlfor!al COmm!fteeS 01 fhe Seclely of Pelf OIIJuM Engineers PelIKUSStOn to copy !s resff!cled to an atM, 3cf of no! more than 300 words Illustrations may not be Colr,ed The abslracf should contain Consptcuoua acknowledgment! of WhOfe and by whom fhe paper m presented Wf?fe Publ!caflons Manage?. SPE.P O Bw 833836. R,chafdson. TX75083.3636Telex.730989SPEDAL