Petrophysical interpretations have included the following :

Canada – computerized log analysis of over 3000 wells

North & South Elswick – 69 well Midale Marly and Vuggy study

Cavalier Area – 45 Viking well project

Countess ‘YY’ – 35 well Glauconite formation study

Lougheed – 37 well Midale Marly and Vuggy study

Lathom ‘A’ – 34 well Glauconite study – reservoir characterization

Cavalier – 45 well Viking study – shaly sand interpretation, gas recognition, gas rate estimation

Oman – 7 well carbonate petrophysical evaluation – multiply horizons

Tunisia – single well, deterministic petrophysical evaluation, Formation Multi-Test (FMT) fluid gradient interpretation techniques

Guatemala – 24 well karsted, fractured, carbonate evaluation

Algeria – GKN-1, DAS-1, MED-1, MED-2, MGD-1, BEL 1 & 2 – Mehaiguene Block – Sonatrach operator.

Italy – detailed fracture reservoir analysis using imaging logs (Schlumberger’s Formation Microscanner) on Monti Alpi 1 & 2, and Cerro Falcone 1 – AGIP operator.

Indonesia – Rajamuda-1a, Langsa Block – Pertamina -TCR operator.

Australia – Langhorne 1, Maple 1, Paqualin 1 – BHP Petroleum Pty Ltd. operator.

North Sea – Caister Field – Block 44/23 – various operators Q13 – 8, Q13 – 10

Studies completed by TELLURIC Petrophysical Consulting Limited

Numac Energy Inc. – North and South Elswick Pools – Marly & Vuggy Formations (69 wells)

The purpose for the study was to provide mappable petrophysical parameters required as input into their reservoir simulation model. Extensive core / log correlations assisting in porosity and permeability determinations, and net pay cutoffs. Culling of fracture influenced core permeability measurements were also performed to derive at a more representative matrix permeability. Extensive textural complexities influencing the cementation exponent and water saturation determinations were handled by deriving a variable ‘m’. Additional cross-plots such as water saturation verses formation subsea elevation were provided to assist in profiling oil/water transition interfaces.

Basic Petroleum International Limited – Guatemala (24 wells)

Responsible for providing geological and petrophysical analysis over a Lower Cenomanian carbonate reservoir. The lithology was predominantly dolomite with porosity and permeability enhanced from karstification and fracturing. The study involved the incorporation of core data for core / core and core / log regression correlations, determination of net pay summaries, average porosity, water saturation, and permeability index (Ki) determination.

The petrophysical analysis formed the foundation for much of the geologic mapping of the reservoir. It also assisted in providing a better understanding of flow units, baffles and barriers within the pool, and a more accurate estimate of the OOIP. This data was then to be incorporated into a flow simulation model to more effectively optimize removal of the remaining reserves.

Gulfstream Resources – Sultanate of Oman (5 wells)

Petrophysical analysis was completed on the Aptian carbonates of the Oman Group. The petrophysical focus was on porosity, water saturation, net gas pay determination, and identification of fluid interfaces. These low porosity limestones were texturally complex as evidenced by the large shifts in water saturation and bulk volume water calculations (up to 75% Sw with little water produced on production tests). Because of the textural variations within the reservoir, calculated water saturation cutoffs for the estimation of net pay proved to be of little value.

The presence of secondary porosity types such as fractures (qualitatively identifiable on logs) and vugs also affected the “m” exponent. To assist in fine tuning the water saturation calculation, a variable “m” cementation exponent was provided (Nugent equation) and proved more beneficial than the constant “m” method.

PanCanadian Petroleum Limited – Cavalier Area – Viking Formation (45 wells)

A study involving initial production gas rates verses log characteristics on cased wells, in an attempt to estimate gas rates formation prior to casing new wells over the very shaly Viking (the Viking typically in this area does not show gas on DST). Since the zone characteristically consists of 30-60% clay, most logs are of little value in the interpretation. The methodology focused on neutron-density porosity differences verses gamma ray API units, the determination of a shaly water line, and gas-effected porosity departures verses initial gas production rates. The technique provided a means of identifying gas effect, and correlating this effect to an expected historic initial gas rate.

PanCanadian Petroleum Limited – Countess “YY” Pool (35 wells)

The projects main deliverables were to provide petrophysical support to the geologic and engineering staff required for the mapping and estimation of OOIP. This OOIP would dictate the remaining OIP.

The Countess “YY” Glauconite (dominantly quartz and chert) reservoir consisted of 4 main facies (tidal bar, bayhead delta, fluvial channel, levee). Each facies possessed it’s own discreet porosity / permeability relationships, and flow unit character. Identification of facies from core, and the recognition of core / log signatures was crucial to the project. Unique facies derived PHIE cutoffs ranging from 7% to 17% were used in the calculation of oil net pay, a 10% PHIE cutoff for gas was independent of facies.

Significant factors which impact the efficiency of the waterflood were identified. Kvert/Kmax plots were completed and indicated two of the facies possessed vertical permeability barriers. Also, bitumen was present in most wells and adversely affected the flood efficiency in the northern portion of the pool, an incorporation of these permeability barriers when reservoir simulation is to be performed was recommended. In addition, a recognition of the short-comings of the core cleaning process was also identified (i.e. bitumen was removed resulting in erroneously high K values). This initiated routine core measurement methodology changes at PanCanadian Petroleum Limited.

 

PanCanadian Petroleum Ltd – Lathom “A” Pool (34 wells)

Responsible for providing petrophysical support to the geologic and engineering staff. The Lathom “A” Glauconite (dominantly quartz and chert lithology) reservoir consists of greater than 7 facies. Similar petrophysical analysis as performed at Countess “YY” was performed here. A major focus was the accurate determination of OOIP and OGIP. To this end, net pay maps determined from petrophysics were hand contoured. These maps included structure of the top and base of the facies so hydrocarbon typing was discerned. The maps were also cross-contoured with the net pay maps of other facies ensuring accuracy to inter-well thicknesses. Volumetric calculation for each facies gave a more accurate estimate of the placement of the hydrocarbons in the reservoir, which resulted in focused recommendations for pool optimization.