PETROLOGY AND FORMATION DAMAGE CONTROL, UPPER CRETACEOUS SANDSTONE, OFFSHORE GABON

Transcription

1 Clay Minerals (1986) 21, 78 t-790 PETROLOGY AND FORMATION DAMAGE CONTROL, UPPER CRETACEOUS SANDSTONE, OFFSHORE GABON E. D. PITTMAN AND G. E. KING Amoco Production Company, Research Center, PO Box 3385, Tulsa, Oklahoma 74102, USA (Received 8 October, 1985; revised 15 November, 1985) ABSTRACT: The subarkosic-sublitharenitic Upper Cretaceous sandstone, which has up to 30% porosity and 585 md permeability, produces on salt diapir structures in the Oguendjo West Block, offshore Gabon. The porosity consists of 68% intergranular porosity of primary and secondary origin, 17% secondary intragranular and moldic porosity, and 15% rnicroporosity. A microcrystalline quartz druse, which was derived from alteration of lithic fragments, coats framework grains and retards the development of syntaxial quartz overgrowths. Other cements are patchy ankerite ( vol%) and kaolinite, which also occurs as a replacement of framework grains. The total kaolinite content ranges from 1.8 to 8.2 vol%. Kaolinite and remnants of altered and partially dissolved lithic fragments are susceptible to movement with fluid flow. Formation sensitivity tests showed that the kaolinite-rich sandstone was stable to 2% NaCI water, but introduction of freshwater caused permeability impairment. Acid treatment to remove damage produced sporadic results. Injection of HCI raised the permeability temporarily, indicating that fines were still being liberated within the pore network. Injection of HCI/HF immediately reduced permeability through partial disaggregation of the rock. Plugging of the formation face by drill mud also damages the reservoir. Reversal of flow at high pressure differentials will remove formation damage produced by face plugging. A guideline for this process established in the laboratory is to backflow with a pressure differential at least as high as the overbalance used in drilling. The combination of oil-based drilling fluids and underbalanced perforating with filtered diesel in the wellbore should eliminate most formation damage in this reservoir. This paper deals with the Upper Cretaceous sandstone reservoirs in the Oguendjo West (OGW) Block about 10 miles off the coast of Gabon (Fig. 1). In the OGW block this sandstone is of Campanian age but is part of a sand lithology that continues into the Maestrichtian (Fig. 2). Some workers consider the entire sandstone to be the Batanga Sandstone, whereas others restrict this name to the Maestrichtian. Because of this confusion, we avoid the term and use 'Upper Cretaceous sandstone'. This sandstone produces on salt diapirs formed by movement of the Aptian Ezanga Salt in the OGW block. Core samples were studied from wells on three structures in the OGW block. All of the samples used for flow tests, however, came from a steeply dipping, thin, oil-saturated zone on a nonproducing structure where the rock, although friable, was sufficiently indurated to cut plugs. The other cores, except for thin zones, were damaged from drying and shipping, and generally unsuitable for cutting long plugs The Mineralogical Society

2 782 E. D. Pittman and G. E. King ATLANTIC L Lv OGUENDJO ( EST ~, 10 ~'~, FXG. 1. Location of the Oguerdjo West Block offthe coast of Gabon. PALEOCENE MAEST. CAMP. SANT. CONIAC. TURONIAN UPPER CRET. SAND (BATANGA SS.) CENOMAN. ALBIAN APTIAN ~t- I _ ~_...~.~ "i I v v v vv v v v Vv vv EZANGA SALT V V V V V V FIG. 2. Generalized stratigraphical sequence for the OGW Block. The Upper Cretaceous sandstone produces on salt diapirs related to movement of the Ezanga Salt. M. Cooper (personal communication, 1985) pointed out that XRD analyses of other Upper Cretaceous sandstone cores in the OGW block indicated dolomite and anhydrite, suggesting that the detrital and/or authigenic mineralogy is more varied than suggested by the 23 samples from three wells used here. The purpose of this paper is to discuss the petrology and formation damage control problems of the Upper Cretaceous sandstone in the OGW block.

3 Petrology and formation damage control 783 PETROLOGY Techniques The petrology was studied by thin-sections, SEM and XRD. The rock samples were pressure-impregnated with a blue-dyed epoxy resin prior to sectioning. Thin-sections were stained to facilitate recognition of carbonates and K-feldspar using the techniques of Dickson (1966) and Bailey & Stevens (1960), respectively. Point-counts were made using a voice recognition system described by Dunn et al. (1985). A minimum of 300 points were counted per thin-section. Texture and composition The Upper Cretaceous sandstone, examined in cores from three structures, consists predominantly of slightly indurated, moderately sorted, fine-grained sand grains which are predominantly subrounded. The reservoir typically has porosity from 20 to 30% and permeabilities up to 585 md. Based on point-count data (19 samples), the following framework grains are present (in vol% of the total rock): monocrystalline quartz ( ); polycrystalline quartz ( ); K-feldspar ( ); plagioclase ( ); collophane ( ); muscovite (0-1.5); lithic fragments ( ); heavy minerals (trace). Lithic fragments are predominantly highly siliceous and finely textured. The original nature of these lithics is indeterminate. Diagenetic components are discussed below. Compositionally, the sandstones are subarkoses and sublitharenites in a modified Dott (1964) classification. These compositions are based on reconstructed lithology, i.e. by adjusting point-counts for materials that were partially dissolved or replaced. Diagenetic components and diagenesis Sparse pyrite and siderite occur as early diagenetic replacements (Fig. 3). The alteration of lithic fragments also probably started early, leading to the release of silica. The initial silica precipitated as an atypical form: a drusy microcrystalline coat, less than 2 Ftm thick, PROCESS COMPACTION TIME ~- REPLACEMENT PYRITE REPLACEMENT SIDERITE OQ QUARTZ PRECIPITATION KAOLINITE ANKERITE CEMENT AND REPLACEMENT DISSOLUTION OF LITHICS AND ANKERITE LITHICS ANKERITE o[==o ~... o FIG. 3. Generalized diagentic sequence for the Upper Cretaceous sandstone.

4 784 E. D. Pittman and G. E. King on framework grains of various compositions (Fig. 4A-B). These coats are undetectable in thin-section. Where the microcrystalline quartz was absent, a syntaxial overgrowth developed later (Fig. 4B). Microcrystalline quartz coats have been described previously but do not appear to be common. Heald & Larese (1974) reported chert (microcrystalline quartz) coats visible in thin-section in the Oriskany Sandstone of the Appalachian province in the United States. References to void-tilting microcrystalline quartz cement are more common (Jonas & McBride, 1977; Heald, 1956). The origin of microcrystalline quartz cement is uncertain. It may precipitate from porewater or perhaps crystallize from a gel. Versey (1939) suggested that chalcedony precipitates rapidly from highly silica-saturated solutions, which leads to many closely spaced nucleation sites. The same reasoning seems to apply to microcrystalllne quartz. Millot et al. (1963), suggested that high concentration of alkalis in pore-fluids causes precipitation of microcrystalline quartz. The importance of microcrystalline quartz coats in retarding quartz overgrowth development by blocking nucleation sites was first reported by Heald & Larese (1974). Microcrystalline quartz plays a similar role' in this Gabon Upper Cretaceous sandstone. Sparse syntaxial quartz overgrowths formed only where the microcrystauine quartz coats were absent. These overgrowths constitute < 1 vol% of the total rock. The microcrystauine quartz coats do not occur in secondary pores. Some lithic fragments are highly microporous, have ragged grain margins, and no mierocrystalline quartz coats (Fig. 4C). One possible explanation of these features is that dissolution and alteration of this material provided silica for the microcrystalline quartz coats. Randomly oriented and commonly doubly terminated quartz crystals (8-15/~m long), precipitated on remnants of siliceous lithic debris (Fig. 4A) and postdate the microcrystalline quartz coats. Kaolinite ( vol%) formed as replacement of grains and as pore-tilling cement (Fig. 4D). The replacement kaolinite commonly retains the detrital grain outline. In some cases the replacement kaolinite has been forced into the interstices of adjacent grains by compaction. The kaolinite does not occur as a precipitate within moldic macropores, which helps establish the relative timing of events. Ankerite ( vol%) occurs in all samples as a patchy cement, which may be poikilotopic, and as a replacement of argillaceous matrix in two samples. Sporadically, the ankerite partially replaces silicate grains. Secondary porosity occurs in three forms: (i) micropores within altered lithic fragments (Fig. 4C) and among kaolinite crystals (Fig. 4D); (ii) intragranular/moldic macropores developed within framework grains (Fig. 5A); (iii) secondary intergranular porosity formed by dissolution of ankerite cement (Fig. 5B). The framework grains most commonly dissolved are feldspars and lithic fragments, although collophane and garnet also are partially dissolved. A ternary plot (Fig. 6) of porosity types (Pittman, 1979) shows that the Upper Cretaceous sandstone has predominantly intergranular porosity (68%) with significant intragranular-moldic (17%) porosity and microporosity (15%). This is based on the following algorithm to estimate microporosity: Pmlcroporoslt~r = (kaolinite + lithics) x O. 5. The ankerite was not a pervasive cement because the crystal faces of quartz overgrowths are not modified. If ankerite had formed over the earlier authigenic quartz, the crystal faces

5 Petrology and formation damage control 785 "~ a= E ~ N ~ "0 O~ 9 ~ 9 "~ 0 0 ~.~.~. ~ ~on ~ 0 ~ a=g N N

6 786 E. D. Pittman and G. E. King FIG. 5. Photomicrographs. (A) Feldspars (f) and fithic fragments have undergone various degrees of alteration and dissolution. Lithic fragments commonly are substantially dissolved to create moldic pores (m). The rock also has good intergranular porosity. (B) Ankerite (a) cement shows evidence of partial dissolution; however, this cement probably was not pervasive. Pint. PMic.= (Ka ',, ^ PMic. PMold. FIG. 6. Ternary plot of porosity types shows the importance of intergranular porosity, which is of primary and secondary origin. of the overgrowths would be disturbed, but they have a pristine appearance under the SEM (Fig. 4B). Patchy carbonate cement with considerable primary porosity remained with no significant restriction to fluid flow. The process responsible for the dissolution of silicates and carbonates is unknown, but it is perhaps one or more of the following: (i) CO 2 derived from kerogen or some other source; (ii) organic acids derived from decarboxylation of kerogen; (iii) undersaturation of formation water with respect to selected mineral phases.

7 Petrology and formation damage control 787 Compaction started early and continued later than kaolinite formation. Evidently, the patchy ankerite cement stabilized the rock because the secondary pores do not show any evidence of compaction. Hydrocarbons probably entered the rock soon after development of secondary porosity and retarded further diagenesis. Petrological implications for formation damage The sandstone has significant kaolinite (up to 8.2 vol%) and lesser fine siliceous debris within the pore system. Loose or loosely attached discrete particles in pores of sandstones, regardless of mineralogy, may mechanically move with fluids and eventually form 'bridges' or 'brush heaps' that block fluid flow (Krueger et al, 1967). Bridging is dependent on particle size, amount of fines, and pore-throat size (Muecke, 1978). The first sample tested, which contained 2.2 vol% kaolinite, showed no sensitivity to fluids. However, samples tested later contained more kaolinite ( vol%) and developed varying degrees of impaired permeability on contact with freshwater. Introduction of freshwater into a formation often promotes colloidal dispersion and leads to permeability impairment (Jones, 1964). A test made with an initial flow of ppm (15%) NaC1 brine followed by introduction of less concentrated NaC1 solution did not cause formation damage. Formation sensitivity Several cores from an oil-saturated zone in the Gabon Upper Cretaceous sandstone were used in laboratory testing to determine potentially damaging conditions. In core flow testing, the permeability was stable to a 2% filtered (0.45/~m) NaCI water (Fig. 7), but the 50 POROSITY=27.8% DEPTH FT. "0 E >-...I < 1J.I rv I.IJ f START FLOWING 20,000 PPM NaCI WATER -"3~=~--~ START FLOWING 10 I ~ 1;o 2; s;o TOTAL VOLUME OF WATER FLOWED (cc) FIG. 7. Fluid sensitivity test for kaolinite-rich sand shows permeability impairment on introduction of freshwater.

8 788 E. D. Pittman and G. E. King permeability was very rapidly reduced by the injection of freshwater. Attempts to remove the freshwater damage by injection of HC1 or HC1/HF produced sporadic results. In an acid susceptibility test on one of the cores (Fig. 8), there was moderate damage by freshwater after flowing NaC1 brine. Re-injection of the NaC1 brine raised the permeability to near initial values. Injections of HC1 raised the permeability by approximately threefold but did not produce a stable permeability increase. The permeability rapidly decreased following the post-acid jump. This behaviour usually indicates a liberation of fines within the pore network of the core. Injections of HC1/HF immediately reduced permeability. Following each HC1/HF injection, the cores partially disaggregated. Core disaggregation is consistent with results of early well tests on several Gabon wells where excessive formation fines and sand grains were produced following formation breakdown treatments with HC1/HF acid. Additions of HC1 and HCI/HF to the core used in the testing (Fig. 7) also produced erratic permeability behaviour and formation disaggregationo The purpose of acidizing in any sandstone reservoir is realistically limited to damage removal. This damage is most often caused by the drilling mud or completion fluids. The major part of the permeability damage from drilling mud and many completion fluids is face plugging. In several formation damage tests in our laboratories with drilling mud, the permeability could be returned to initial, undamaged values by trimming off the first 2 mm of the injection face. This demonstrates that the drilling mud fines were stopped at the surface of the formation. Although scraping or reaming the pay is impractical for most operations and impossible in cased holes, it was demonstrated that reverse flow at high pressure differentials could reliably clean drilling mud cake damage from the cores. Drilling 250 POROSITY = 29.3% DEPTH = 7315 FT. INJECT 10cc 200 "o g >- I-._1 < u.i rr I..H r, t START FLOWING ] / 20,000 PPM / / NaCI WATER / / / STARTED FLOWING / / / FRESH WATER I / / INJECT 10cc HCI/HF 50 1( J /I//NjECT HCI RESTART/ 20,000 PPM NaCl WATER 0 I I I I I I I I I I TOTAL VOLUME OF FLUID FLOWED (cc) FIG. 8. Formation was moderately damaged by introduction of freshwater. HCI improved the permeability. Use of HC1/HF caused disaggregation of the sample and formation damage. 2000

9 Petrology and formation damage control POROSITY = 29.3% DEPTH = 7315 FT. REVERSE FLOW ECTION "o >-._.1 < uj n," W O NORMAL FLOW DIRECTION ~ 4,------~ INJECTED 10cc 50 FRESH WATER MUD ORMAL FLOW DIRECTION l I I TOTAL VOLUME OF NaCI WATER FLOWED (cc) I 1000 FIG. 9. Drilling mud damage of a core was easily removed in this test by reverse flow. mud damage of a core from this Gabon sandstone was easily removed in testing by reverse flow (Fig. 9) The guideline for drilling mud damage removal, which has been established by numerous tests in our laboratories, has been to backfiow with a pressure differential at least as high as the overbalance used in drilling. Routine recoveries of at least 80% of initial permeability are common with this treatment. In applying-this information to the field, it has been determined that perforating with the pressure differential toward the wellbore may remove a considerable amount of the damage, which would otherwise have required an acid treatment (Krueger, 1956; Allen & Worzel, 1956). The underbalance necessary for clearing the perforations and any small fractures or damage will depend on permeability (King et al, 1985). When the wellbore pressure is less than the pressure in the formation, the flowing formation fluids will clear much of the debris from the perforations. Very high underbalance pressures should be avoided, because weak formations can actually be flowed through the perforations at high drawdown pressures. To further reduce potential damage from water-based fluids, a switch was made to oil-based drilling muds. The combination of the oil-based fluids and underbalanced perforating with filtered diesel in the wellbore should eliminate most completion damage in this reservoir. ACKNOWLEDGMENTS The authors thank Amoco Europe and West Africa, British Petroleum, Deutche Schachtban, Petrogab, Preussag and Wintershall for permission to publish this paper.

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