Wettability changes during stages of restored state core analysis were evaluated for a North Sea reservoir. The goal was to determine the proper technique for estimating the remaining oil saturation after proper technique for estimating the remaining oil saturation after waterflooding from core analysis. The traditional methods for quantifying wettability, i.e., USBM and Amott Indices and the Brownell-Katz correlation, were evaluated. It was found that the USBM and Amott procedures. when modified slightly, could be interpreted to give a good Indication of wettability. The traditional method of cleaning cores by Dean-Stark extraction with toluene followed by chloroform/methanol was found to be ineffective in making a core water-wet. To overcome this difficulty, we evaluated core cleaning procedures that employ a sequence of solvents. The remaining oil saturation increased from 9% with crude oil In the "as received" state to 28% with refined oil after the third cleaning. Once the cores were made water-wet, aging the cores in a North Sea crude oil returned them to a mixed-wet state. However, the restored state cores were not as oil-wet as the "as received" state cores. Even after aging, there was a significant difference between the cores cleaned by Dean-Stark extraction and by a sequence of solvents. The mixed-wet condition with the North Sea crude oil is, therefore, expected to apply to the field: the crude oil base number, isoelectric point, effluent pH during core floods, and bottle wettability tests support point, effluent pH during core floods, and bottle wettability tests support this contention. Examination of the Brownell-Katz number correlation and the capillary pressure curves showed that much of the remaining oil saturation In a pressure curves showed that much of the remaining oil saturation In a mixed-wet core during core analysis could be due to retention by a capillary end effect. This was supported by a CIA scan of the core. In this mixed-wet reservoir, the remaining oil saturation is not equal to the residual oil saturation, but must be calculated using the appropriate relative permeability curve and the effect of buoyancy. Introduction There are two approaches for analyzing cores under the proper wettability conditions. "native state" and "restored state" analyses. (See Reference 1 for literature survey.) Native state analysis requires that the wettability state of the core be preserved at the in situ state. This requires that the core be protected from drilling fluid contamination, evaporation, oxidation, and freezing. If this could be accomplished successfully, it would avoid the effort of the restored state analysis. Since core preservation is often questionable and difficult to verify, however, restored state analysis is often wed. Restored state analysis requires that the core be cleaned to the water-wet state that existed before oil accumulated in the formation. The core is then saturated with crude oil to a capillary pressure typical of the formation and the system allowed to equilibrate or "age" under conditions representative of those existing in the formation. SYSTEM EVALUATED Sandstone cores from a North Sea field, having brine permeabilities in the range 200-500 md and porosities of about 0.25. were used. P. 361

Pressure transient theory for a water-injection well in the presence of a closing fracture and a discontinuity in fluid mobility is developed in elliptical coordinates. Solutions are obtained using the Laplace transform and numerical inversion. From the results it is concluded that a pressure fall-off test with a closing fracture, in principle provides three different methods for determining the fracture length. The first method is based on rock mechanical principles only. The second method makes use of formation linear flow. The third method analyses the transition of the pressure transient from the inner fluid region to the outer region in conjunction with a heat or volume balance. If more than one method is applicable consistent results should give a reliable estimate of the fracture length. The in-situ horizontal rock stress can also be determined from the test. It is equal to the pressure at which the closing of the fracture is observed.

The development of an oilfield in the North Sea is characterized by costly appraisal drilling and very long lead times necessary to design and build platforms. This paper describes the evolution of development plans for the North Sea Brent field, a field that is composed of two oil plans for the North Sea Brent field, a field that is composed of two oil reservoirs, both of which are overlain by condensate-rich gas caps. Introduction The development of a North Sea oil field such as the Brent field, which consists of two reservoirs covering an area about 17 x 5 km in Block 211/29, is characterized by costly appraisal drilling and very long lead times necessary to design and build platforms. As a result, a large amount of capital must be committed and spent before a clear understanding of the reservoir has emerged. The present program includes pressure maintenance largely by injection of treated sea water and provision for a gas sales scheme with British Gas Corp. provision for a gas sales scheme with British Gas Corp. This means that full secondary recovery projects will have been committed before the reservoir has been produced. The potential reservoir performance for various producing mechanisms was predicted using numerical and physical models that were constructed on the basis of a seismic structure map and control from only the first two wells. Most early decisions were based on the results of this work. This paper discusses the early work and describes how development plans have evolved as additional data have been obtained from new wells and as more detailed studies have been completed. Fig. 1 shows the location of the Brent field. It is situated about 150 km from the Shetland Islands in an area of the North Sea with a water depth of 470 ft and where wind speeds up to 125 miles/hour and waves of 100 ft have been observed. Early exploration drilling in this area appeared promising. The regional seismic picture showed some very large structures with estimates of picture showed some very large structures with estimates of potential reserves ranging up to 2 billion bbl. The Brent potential reserves ranging up to 2 billion bbl. The Brent field discovery well was drilled in the summer of 1971. Because of the severe weather conditions in the Brent field area, semisubmersible drilling vessels available at that time could only operate from May through August and appraisal drilling was delayed until the following summer. Since that time a large number of exploration wells have been drilled in the northern North Sea and the great potential of this environmentally hostile area has been confirmed by the discovery of other major gas and oil fields. Significant technological advances in rig and platform construction, offshore loading systems, subsea well completions, and deep-water pipeline laying are being made to develop these fields. Historical Development A feasibility study for the development of North Sea oil fields was carried out at the beginning of 1971. The aim of the study was to evaluate the economics of developing North Sea oil fields for a wide range of environmental and reservoir conditions. One of the potential fields studied was an anticlinal seismic event in Block 211/29, and development of both an undersaturated reservoir and a reservoir having a gas cap were considered. In Aug. 1971 oil was discovered in Well 211/29-1, the most northerly well to be drilled in the North Sea at that time. Log evaluation indicated a 180-ft gross hydrocarbon-bearing column within an 800-ft-thick Middle Jurassic sand interval. JPT P. 1190

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Summary. Shell Expro and Koninklijke/Shell E and P Laboratorium (KSEPL) havebeen engaged in a multidisciplinary effort to determine the waterflood residualoil saturation (ROS) in two principal reservoirs of the Cormorant oil field inthe U.K. sector of the North Sea. Data acquisition included special coring andtesting. The study, which involved new reservoir- engineering and petrophysicaltechniques, was aimed at establishing consistent ROS values. Reservoir-engineering work centered on reservoir-condition corefloods in therelative-permeability-at-reservoir-conditions (REPARC) apparatus, in whichrestoration of representative wettability conditions was attempted with theaging technique. Aging results in a consistent reduction of water-wetness ofall core samples. The study indicated that ROS values obtained on aged cores atwater throughputs of at least 5 PV represented reservoir conditions. Thepetrophysical part of the study involved ROS estimation from sponge-coreanalysis and log evaluation. Introduction Knowing the ROS to waterflood is very important both to manage waterfloodsin progress and to define possible long-term EOR targets. Shell Expro and KSEPLhave therefore been engaged in an integrated campaign to determinerepresentative ROS values in the Cormorant field. The in-situ measurementtechniques include logging and single-well tracer testing in Wells CormorantCA-28 and CA-29. Laboratory measurements included saturation measurements onpreserved whole core pieces cut from sponge core, countercurrent imbibitionexperiments, and corefloods under reservoir conditions with real reservoircrudes and brine. Reservoir-condition corefloods were performed in KSEPL's REPARC-2 equipment. REPARC-2 works on the basis of the restored-state, whichentails making a core sample water-wet by an appropriate cleaning procedure andsubsequently exposing it to reservoir crude and brine at connate watersaturation for a long enough time to establish the appropriate wettability(aging). In this paper we discuss the results of these techniques and attemptto reconcile obtained data. Sponge Coring Sponge coring is similar to conventional coring except that an aluminumliner, enclosing a porous, oil-wet polyurethane sponge is run inside the corebarrel. During the coring operation, the core enters the liner and fits tightlyinside the sponge. As the core is brought to the surface, gas comes out ofsolution inside the core, expelling water and possibly oil out of the core. This oil is normally trapped by the sponge; experience has shown that no oil islost from the liner when the core is brought to surface. The amount of oil inthe core and sponge can be measured and converted to in-situ conditions byapplying the oil FVF. PV in the core is adjusted for compaction with thestress-affection factor. Thus, in flooded zones, an estimate of in-situ Sor canbe obtained. A total of 323 ft of core was cut in Well Cormorant Well CA-29ST1 with a recovery of 263 ft (81 %) over the interval from 13,435 to 13,762 ftbelow derrick floor (BDF) in the Upper Ness, Lower Ness, Etive, Rannoch, and Broom formations. The entire core, still sealed inside the liner, was inspectedby X-ray tomography, and representative sections of the flooded and unfloodedintervals were selected for Dean-Stark analysis. The selected core intervalsand liner were cut into 0.3- to 1.0-ft pieces (whole core) and all oil andwater in both, as well as in the sponge, were removed by Dean-Stark extractionwith toluene as solvent. The volume of water was collected and measured; theoil remained in the toluene. The total weight of oil originally present in thecore plow was calculated from the difference between the weight of watercollected and the initial and dry weight of the core and sponge. Across theintervals in the Lower Ness and Etive formations, which from log data appear tobe the most completely flooded, the measured oil saturations ranged from 20 to52% and 22 to 43%, respectively. Across the interval considered to be floodedin the Lower Ness, up to 75 % of the total oil volume was found in the sponge, indicating that the majority of the zone may not be at irreducible orsaturation. An indication of Sor is obtained from 2.5 ft of core at the base ofthe flooded interval where there was practically no oil in the sponge and Sowas found to be 25% (measurement range of 20 to 30%). Across the floodedinterval in the Etive, little or no oil (4 % maximum) was found in the sponge, indicating that this zone is prodominantly at ROS. The most reliable Sorestimate is obtained prodominantly at ROS. The most reliable Sor estimate isobtained from the lowermost 4 ft of core, where So was found to be 25% (22 to28%). REPARC-2 Measurements Equipment. Fig. 1 is a schematic of the apparatus. The main parts of theequipment are oil and brine supply vessels, two core holders, productionvessels, a pressure-regulations system, differential production vessels, apressure-regulations system, differential pressure transducers, and adisplacement pump. The core holders pressure transducers, and a displacementpump. The core holders normally contain standard 1-in. cylindrical plugsbetween 2 and 5 in. long. The core plugs are embedded in epoxy resin in a monelmold. The volumes of produced fluids from the core plugs are measured inspecial production vessels. The principle of these measurements is the changingelectrical capacitance as the oil/water interface moves through the productionvessel. Core-Plug Selection and Preparation. From the results of X-ray tomography onsponge cores from Well Cormorant CA-29S1 in both Etive and Lower Nessformations, four core pieces were selected for REPARC-2 experiments. Plugs 1 in. in diameter and about 3 in. long were cut along the bedding plane from Cores 6.1.2 and 6.3.3 of the Lower Ness and Cores 12.6.3 and 13.3.6 of the Etive. Some difficulties were encountered in the experiments on the first plugof Core 13.3.6 (Plug 13.3.6.A), so two other plugs (Plugs 13.3.6.B and13.3.6.C) were taken for duplicate measurements. The coreplugs were thoroughlycleaned by Dean-Stark extraction with toluene for 24 hours, followed by asubsequent extraction with a chloroform/methanol mixture (70/30 vol%). The coreplugs were dried at 140 degrees F under light vacuum while nitrogen, humidifiedunder room conditions, flowed slowly through the stove. The dry cores werewrapped in teflon tape and centered in a monel mold. The annular space betweenthe mold and the core plug was filled with liquid epoxy resin that was thenallowed to cure at an elevated temperature (284 degrees F) for 24 hours. SPEFE P. 39