Anaerobic bacteria were identified in live drilling muds and cores from nine different North Sea and Irish Basin oilfields, varying in depth from 3500 to 15000 ft, and at temperatures up to 150°C. The anaerobic bacteria may be introduced into the reservoir during drilling operations or injection of water, but in many cases the bacteria are indigenous to the oilfield reservoirs. Confirmation of the indigenous anaerobic bacteria was made using molecular biology techniques (16S rDNA sequence analysis), comparing microbial populations present in the blank drilling mud as supplied to wellsite, in the live drilling mud taken during coring, and in the live core. The role of anaerobic bacteria in oilfield diagenesis is not fully understood, though pyrite precipitation, and exopolymer and H2S gas production were noted in this study, up to temperatures of 95°C.

Laboratory reservoir conditions flood tests were used to determine the clean up efficiency of a drilling mud that was applied at two different overbalance pressures. The test was designed to simulate, as closely as possible, the conditions occurring in the reservoir during the drilling operation. Relevant core material was used and the pore/overburden pressures, mud overbalance pressures, temperature and production drawdown pressures/rates applicable to field conditions were applied in the laboratory simulation. Drilling mud filtrate volume loss versus time measurements were made at reservoir conditions using sophisticated pumps. All wetted parts of the rig were constructed of hastelloy C276 alloy to avoid corrosion artifacts interfering with the test. Permeability measurements were made prior to mud application and again at the end of the flood test analysis to determine the level of any formation damage. In order to determine the nature of the formation damage mechanisms, geological techniques which included dry and cryogenic SEM and thin section analyses were undertaken. These techniques were applied to the plug trims prior to testing (untreated samples) to determine the natural state of the rock, paying particular attention to the clay mineral and cement types, morphologies and distributions. The plug samples were examined at the end of testing (treated samples) and any variations noted which would highlight the damage mechanisms. The dry SEM and thin section analyses were used to determine solid damage mechanisms such as clay fines migration, scale precipitation and drilling mud solids invasion. The cryogenic SEM analyses were used to examine any fluid damage mechanisms such as wettablity alteration, microemulsion formation, water/oil blocks or fluid retention. A new technique of cryogenic SEM using EDX (Energy Dispersive X-Ray) analysis was used for X-ray mapping of the remnant mud bodies to determine solid and fluid distributions. Introduction The objective of the laboratory analysis performed was to determine the effect of high over balance during drilling followed by simulated return to production on the productivity from a particular lithology in an oil well. Any damage mechanisms and there impact on productivity were to be fully investigated and implications for future drilling and completion highlighted. A series of reservoir conditions core flood tests were designed to measure the permeability changes caused by different well conditions1. The core flood tests were designed to simulate as closely as possible the real wellbore conditions. Thorough sample evaluation was used to identify all damage mechanisms and reasons for measured permeability changes. Combinations of standard and innovative sample evaluation techniques were used to examine the core plug samples after the flood tests and the external bodies developed during mud application and remaining after simulated return to production. Core Flood Test Procedures Sample Selection and Preparation. A total of six one inch diameter core plug samples were cut from a wax preserved whole core sample. The plug samples were cleaned using a warm submerged soxhlet cleaning technique and dried in a 60°C dry oven. End face debris caused during trimming of the plug samples was removed using the acetate peel technique2. Base parameters of porosity, permeability and grain density were measured. The plug samples were C. T. scanned in order to view any heterogeneity or anomalies which might adversely affect the core flood testing. Three samples were selected to be representative of the target lithology and with relatively similar base parameters. The three samples were initially saturated 100% to simulated formation water (see below) and then spun to irreducible formation water saturation using an ultracentrifuge. The ultracentrifuge technique is used in order to obtain a consistent, repeatable saturation relatively quickly without mobilising fines within the plug samples. Sample Selection and Preparation. A total of six one inch diameter core plug samples were cut from a wax preserved whole core sample. The plug samples were cleaned using a warm submerged soxhlet cleaning technique and dried in a 60°C dry oven. End face debris caused during trimming of the plug samples was removed using the acetate peel technique2. Base parameters of porosity, permeability and grain density were measured. The plug samples were C.T. scanned in order to view any heterogeneity or anomalies which might adversely affect the core flood testing. Three samples were selected to be representative of the target lithology and with relatively similar base parameters. The three samples were initially saturated 100% to simulated formation water (see below) and then spun to irreducible formation water saturation using an ultracentrifuge. The ultracentrifuge technique is used in order to obtain a consistent, repeatable saturation relatively quickly without mobilising fines within the plug samples.

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractFormation damage in terms of physio-chemical reactions such as asphaltene deposition, scale precipitation and fines migration for example, is relatively well understood. In contrast to this the effects of indigenous and introduced microbes and their role in oilfield formation damage is less well understood. Oilfield microbes, especially the S.R.B. (sulphate reducing bacteria) have been identified from many oilfields world wide (indigenous) and have been isolated from drilling mud (particularly water based muds) and other downhole chemicals and injection water (introduced microbes).The combination of the various microbial populations often results in the precipitation of insoluble metal sulphides, biopolymer and/or hydrogen sulphide production, with loss in production or injection rates. By utilising bottle tests performed at a range of temperatures up to the actual oilfield reservoir temperature, it is possible to model the microbial formation damage mechanisms using the thermal gradients present in the field. Using this thermal model it is possible to predict where the various microbial formation damage mechanisms, such as hydrogen sulphide production, biopolymer and cell pore blockage, occur in the field area and to predict from the injection water model when the various damage mechanisms will occur in the field. This novel approach using thermal models coupled with microbial bottle and flood tests, and geological interpretative techniques, is the initial step in predicting microbial formation damage in oilfield reservoirs.

The sulphate-reducing bacteria (SRB) produce the toxic gas hydrogen sulphide (H2S) and cause numerous problems in the oil and gas industry. It has been suggested that these organisms are either introduced to the formation by drilling or water injection or that they may be indigenous. Little is known of the activity and survival mechanisms of the SRB under reservoir conditions. In this study a number of samples from hydrocarbon reservoirs were inoculated into sulphate-rich growth medium to determine the presence and activity of the SRB. The samples studied included freshly drilled core material and live drilling muds. The majority of samples analysed contained SRB which produced HzS to varying degrees following different incubation times. Organisms capable of producing H2S at temperatures up to 95~ were detected. Often long incubation periods, in excess of 6 months, were necessary before H2S was produced.

Four major sedimentary sequences of the Triassic and Upper Jurassic of the Main Claymore Oilfield of the North Sea each contain a characteristic suite of diagenetic minerals and fabrics. (1) Triassic Skagerrak Formation fluvial sandstones contain early authigenic pore-lining smectite, together with kaolinite and chlorite which form grain replacements and pore fills. Quartz and feldspar overgrowths are minor. Ferroan dolomite forms a late diagenetic patchy poikilotopic cement. Smectite is converted to illite-smectite in a 5 m thick zone beneath the sub-Jurassic unconformity. Smectite formed early in diagenesis prior to oil migration and destroyed permeability. Thus oil is not found in these sandstones although they occur in the oilzone. (2) The Piper Formation (late Oxfordian/early Kimmeridgian) paralic deposits mainly contain authigenic, pore-lining illite-smectite, vermicular kaolinite grain replacements and pore fills. Quartz overgrowths are generally well developed. (3) The Kimmeridge Clay Formation (early Kimmeridgian/early Volgian) comprises thin marine sandstone turbidites, contained within a thick siltstone/shale sequence. In the sandstones (the 'Ten Foot Sandstone') discrete double-ended quartz crystals (1-20 #m) developed prior to quartz, K-and Na-feldspar overgrowths. Only minor kaolinite and lllite-smectite are present. Late diagenetic dolomitic occurs as a patchy poikil0topic cement and as clusters of pore-filling rhombs. (4) The Claymore Sandstone Member (early to middle Volgian) thick marine sandstone turbidites are interbedded with thin siltstones/shales. Sandstones have well-developed quartz, K and Na-feldspar overgrowths, and kaolinite and illite-smectite occur as grain replacements and rarely as pore fills. Late-diagenetic dolomite and ferroan dolomite form poikilotopic cement and clusters of pore-filling rhombs. The major factors which control diagenetic features are depositional environment and associated porewater together with original mineralogy. Burial history and textural features of the sandstones also have important influences. Reservoir quality is controlled by a complex interplay of these features.