Formation Test Research Articles

Integrating Pressure Data From Formation Tester Tools and DSTs To Characterize Deepwater Fields, East Kalimantan, Indonesia

Summary In the past 3 years, two significant commercial hydrocarbon accumulations in the deep waters of the Makassar Strait, Indonesia, were discovered. These fields are located approximately 16 miles northeast of the giant Attaka field in 1,400 to 3,400 ft of water. To date, more than 40 exploration and appraisal wells have been drilled in both fields, and extensive pressure data have been collected by formation tester tools and drillstem tests (DSTs). The pressure data, used with other data such as seismic and well logs, have enabled us to characterize deepwater turbidite sand reservoirs. In this deepwater environment, DSTs are used selectively and only with strong justification because of their prohibitive cost. Instead, the use of the pressure-testing tool is pushed to its limit to gain extensive data on pressure, rock, and fluid properties conventionally obtained by DSTs. This paper will show how the deepwater reservoirs were characterized by means of pressure data from formation tester tools and DSTs to complement geological and seismic data interpretations. Reservoir characteristics such as fluid type, fluid contacts, reservoir connectivity, and sand geometry can be inferred from the pressure gradients and pressure transients. These data are used in constructing reservoir fluid-flow models for a field-development plan.

The ‘tight gas’ challenge: appraisal results from the Devonian of Algeria

Projected future increases in Algerian gas production will, in part, come from more complex reservoirs within the Ahnet-Timimoun Basin; here, conventional quality reservoirs (>1 mD) are interbedded with volumetrically significant, low permeability sandstones (<1 mD) – the ‘tight gas’ sandstones. The challenge has been to develop a programme of work which will establish reserves in this sub-millidarcy resource; on balance, the results of this evaluation programme are positive. The main tight gas sections are of Lower Devonian age. Grain rimming chlorite cement within thin intervals locally inhibited later pervasive quartz cementation; the quartz is the cause of reservoir degradation in the bulk of the sandstone resulting in permeabilities of <1 mD, and often in the microdarcy range. Generally, the Lower Devonian has a low density of faulting and fractures; open and closed fractures are observed in core, whilst mud losses suggest some fractures are conductive in the subsurface. One of the main structures, the Teguentour Field, has been evaluated through the drilling of two new wells. The first of these wells (Teg-14) evaluated interbedded tight and conventional sandstones, whilst the second (Teg-15) was a dedicated tight sandstone completion involving an induced fracture programme. The permeability range in the tight gas sandstones extends below the resolution of conventional porosity/permeability measurement; determination has been improved through mercury injection derived permeabilities. Water saturations determined from core and log suggest gas may be present in the low permeability rock. The presence of gas could not be confirmed by formation tester samples and thus dynamic data were required from the Teg-15 well which was completed within the tight sandstone interval; only the top 5 m was perforated to limit the possibility of a communication pathway down to conventional quality sandstones. After nitrogen lift, the well flowed gas to surface at c. 5 ×10 4 SCFD for several hours. The low leak-off coeffcient determined suggests there was no connection to a pervasive conductive fracture network, although fractures intersected by the wellbore may have contributed to flow. Also, large poro-elastic back stresses indicate that a connection to high matrix or fracture permeability was unlikely. On balance, the test is a positive indicator of gas presence in very low permeability/porosity rocks which may recharge associated conventional layers following suffcient drawdown.

Geopressure Compartmentalization in Keathley Canyon, Deep Water, Gulf of Mexico

ABSTRACT In the Gulf of Mexico, several salt related basins have attracted exploration. Keathley Canyon Block 255 Well #1 (TD 21550) has tested one of these basins. Extensive geological and Repeated Formation Tester data were collected from this well. Integration of the geopressure profile and the structural setting demonstrates two distinctive main compartments. A hydrodynamically active compartment exists between the sea floor and the Hyalinea balthica upper Pleistocene shale section. This phenomenon may be responsible for the drilling problems and shallow water flow in this and similar relatively young basins. Therefore, entrapment of commercial volumes of hydrocarbon in this upper section is unlikely. A hydrostatically geopressured main compartment extends between the upper effective seal of Hyalinea balthica to the Pliocene section at the bottom of the basin. This geopressured thick section shows a progressive pressure profile with depth and can be divided into five mini-compartments (C1, C2, C3, C4, & C5). Four of these mini-compartments show effective seals (S1, S2, S4 & S5). On the other hand, on both sides of the incompetent seal (S3), the pore-pressure gradient remains in the same hydrostatic envelope. This also exhibits communication between C2 and C3 and indicates exploration targets in the C3 are high risk. Seals and reservoir lithology have a direct impact on the geopressure profile progression with depth. On the other hand, the structural setting is responsible for pore pressure differential between the seal and reservoir (centroid concept). Drilling on the crest of high relief closure can be a challenging task in deep water exploration.

Development of the Combinatorial Glass Formation Tester

AbstractThe combinatorial glass formation tester has been developed to determine the glass forming regions as quickly as possible. The 24 glass batches of about 1g were put into each carbon crucible on a carbon holder and heated in an electric furnace filled with dry nitrogen gas. After about a half an hour heating, the crucibles were taken out from the furnace and moved into the cooling chamber purged with dry nitrogen gas. The holder and the crucibles were moved on to a cooling stage to be cooled down quickly with a water flowing jacket together with nitrogen gas blowing. The time interval after taking out of the crucibles till the placement on the cooling stage was shortened as much as possible, resulting to be 10sec. The temperature of the melt in the crucibles was measured with an optical pyrometer to estimate the cooling rate. The top view of the crucibles on the holder was taken with a CCD camera during cooling. The CCD figures were stored on a computer for the judgments of the transparency of the samples in the crucibles to compile a glass forming region. The glass formation tester can manage 24 glass melting tests every 1 hours. In other words, the tester can produce at least 192 glass samples (24 x 8=192) within a day working time. The speed was roughly 100 times larger than the case of manual operation.

Development and Application of a System for Determining Paper Nonuniformity

The nonuniformity of paper is one of the important factors affecting print quality etc. The Density variation of paper is the most important factor of the nonuniformity of paper, however, it cannot be measured because of no appropriate instrument. A system for determining paper nonuniformity, including density variation, was developed and applied to the specimens. The system comprises the three dimensional thickness tester, the beta formation tester, the micro-photometer and PC for image analysis. In this article, we describe the system configuration and the measurement results of the nonuniformity of newsprint and the felt mark intensity on laboratory sheets.

Adverse Effects of Poor Mudcake Quality: A Supercharging and Fluid Sampling Study

Summary Wireline formation testers are routinely used at discrete depths of a well to collect reservoir fluid samples and to estimate undisturbed reservoir pressures, near-wellbore formation permeabilities, fluid compressibilities, and saturation pressures. A pressure profile in the vertical direction yields fluid densities and fluid contacts (gas/oil and water/oil contacts) in the reservoir. Reliable results are obtained when the mudcake isolates the wellbore from the formation. When the mudcake cannot provide isolation, mud filtrate invasion continues and supercharging occurs. The issue of sample quality becomes critical when using oil-based muds because the filtrate is also oil and is difficult to separate from the formation oil, a pure sample of which is needed for fluid characterization studies. This study investigated the effects of poor mudcake seal on sample quality and formation test data and its analysis when oil-based muds are used. Modeling studies were conducted using a finite-element simulator. The results of the study indicate that mudcake permeabilities must be less than 1 μd and mudcake-to-formation permeability ratios must be less than 10−4 to achieve sample qualities higher than 90%. Such conditions as high pumpout rates, low overbalance pressures, and shallow filtrate invasion depths improve sample quality. The presence of a permeability-damaged zone around the mudcake improves the sample quality but reduces the sampling pressure. The formation rate analysis (FRASM)† technique estimates formation permeability accurately in the presence or absence of supercharging. The formation pressure estimated using the buildup data is the pressure at the mudcake-formation interface. The supercharged pressure must be subtracted from the apparent formation pressure to obtain the true formation pressure. A simple procedure is developed for estimating the mudcake permeability and the supercharged pressure. Supercharged pressure is shown to be a product of the apparent overbalance pressure, mudcake-to-formation permeability ratio, and an invasion factor representing the distance up to which supercharging extends.

Operational Procedures and Applications of a Wireline Formation Tester To Accurately Characterize the Gas Composition of Stacked Multiple Pools in the North Malay Basin

Summary In this article we review the development of techniques to acquire reliable reservoir gas samples using a wireline formation tester in the Malaysia-Thailand Joint Development Area. This region is characterized by gas accumulations comprised of multiple stacked separate pools where reservoir conditions are often considered hostile for wireline logging operations. In the article we use data from the 16-well exploration and appraisal program, during which 1968 pre-tests and 124 samples were successfully acquired, to compare the quality of gas samples from a wireline formation tester with those obtained from drillstem tests in the same zones.

ABSTRACT: A Novel Application of Nuclear Magnetic Resonance and Formation Tester data for the determination of gas saturation in Pretty Hill Sandstone Reservoirs, Onshore Otway Basin

ABSTRACT: A Novel Application of Nuclear Magnetic Resonance and Formation Tester data for the determination of gas saturation in Pretty Hill Sandstone Reservoirs, Onshore Otway Basin

ABSTRACT: Layer Productivity Prediction based on NMR and Wireline Formation Tester Data

ABSTRACT: Layer Productivity Prediction based on NMR and Wireline Formation Tester Data

A Model To Predict Wireline Formation Tester Sample Contamination

Summary Wireline formation testers (WFTs) collect fluid samples for pressure-volume-temperature analysis through a probe set against the borehole wall. Filtrate contamination is reduced prior to sampling by either pumping the mixture of filtrate and reservoir fluid from the formation to the borehole or flowing the mixture into one or more WFT chambers. The cleanup is monitored at the surface. The time to reach the level of acceptable contamination (LAC) depends on the depth of invasion, pumpout rate, and various fluid and rock properties. Generalized guidelines predict time to first oil based on simple volumetrics but do not predict the rate of cleanup. Excessive cleanup time increases costs and the risk of differential sticking of the tool/cable. In some cases it may not be practical to attempt the operation as the LAC may take too long to achieve. A numerical simulator was used to investigate the characteristics of the contamination level versus time curve and to define the variables governing cleanup. The model was validated using data from five wells from two fields with differing rock and fluid properties. One hundred and fifty simulation runs were made with different invasion depths, flow rates, and rock and fluid properties. An equation was developed for field use that estimates filtrate contamination fw as a function of cleanout time t. An alternative approach for WFT sampling is also suggested, using not one but two probes. With this method, both cleanup time and the final level of filtrate contamination can be substantially reduced.

Interpretation of Wireline Formation Tester (WFT) Data In Tight Gas Sands

Abstract This paper summarizes the analysis of wireline formation tester (WFT) data collected in tight gas sands. An interpretation algorithm based on type-curve matching is used in the analysis. The type curves are constructed using an analytical model. The model assumes hemispherical flow geometry and incorporates early time decompression period and flowline storage effect. The permeability values calculated using this algorithm agree reasonably well with the permeability values available from core measurements. Introduction Pressure data from WFT have been used to determine initial reservoir pressure, vertical pressure distribution, fluid contacts, and formation permeability. A WFT tool typically has a probe, piston, pressure gauges, one or two pretest chambers, sampling tank, and flowlines. Figure 1 gives a schematic of the WFT tool with one pretest chamber. Formation fluid is withdrawn into either pretest chamber or sampling tank. Before the test starts, the tool is subjected to the drilling fluid hydrostatic pressure. The test is started after the packer on the tool isolates the formation from the drilling mud in the wellbore. The probe is inserted into the formation through the mudcake. When the tool is used in pretest mode, the piston is pulled at a specified constant rate, and formation fluid is withdrawn into the pretest chamber through the flowlines. During this drawdown period, the pressure in the tool decreases continuously. Once the piston movement is stopped, formation fluid continues to flow into the tool. The pressure in the tool rises gradually until it reaches formation pressure. A wireline formation test consists of three periods: decompression, drawdown, and buildup. During all three periods, the pressure in the tool is recorded. Figure 2 illustrates the piston displacement rate, sandface-flow-rate and the expected pressure response for an ideal WFT test conducted in a low-permeability environment. The pressure in the WFT tool prior to the test is the hydrostatic mud pressure (Pmi), which is higher than formation pressure (Pi) After the piston is activated, the chamber volume increases and the fluid in the tool decompresses. Flow from the formation may start only after the pressure in the tool is lowered below the formation pressure. The period from the beginning of the test to the start of formation flow is referred to as the decompression period. During this period, the pressure decline is solely due to the decompression of the fluid in the flowlines. The drawdown period starts when the tool pressure reaches the formation pressure. In the drawdown period, the pressure response is a function of the fluid decompression and formation flow. Because of limited flow from the low permeability formation, the pressure response is dominated by fluid decompression. Once the piston is stopped, the buildup period starts and the formation-fluid-flow into the tool compresses the formation and flowline fluid back to pretest conditions. The pressure in the tool gradually builds up to initial formation pressure, provided the test lasts long enough. Formation permeability is deduced from the pressure behaviour observed during either the pretest phase(1–4) or the sampling period(5–7).

Determination of Producible Hydrocarbon Type and Oil Quality in Wells Drilled With Synthetic Oil-Based Muds

Summary Determination of the type and quality of hydrocarbon fluid that can be produced from a formation prior to construction of production facilities is of equal economic importance to predicting the fluid rate and flowing pressure. We have become adept at making such estimates for formations drilled with water-based muds, using open-hole formation evaluation procedures. However, these standard open-hole methods are somewhat handicapped in wells drilled with synthetic oil-based mud because of the chemical and physical similarity between the synthetic oil-based filtrate and any producible oil that may be present. Also complicating the prediction is that in situ hydrocarbons will be miscibly displaced away from the wellbore by the invading oil-based mud filtrate, leaving little or no trace of the original hydrocarbon in the invaded zone. Thus, normal methods that sample fluids in the invaded zone will be of little use in predicting the in situ type and quality of hydrocarbons deeper in the formation. Only when we can pump significant volume of filtrate from the invaded zone to reconnect and sample the virgin fluids are we successful. However, since the in situ oil and filtrate are miscible, diffusion mixes the materials and blurs the interface; as mud filtrate is pumped from the formation into the borehole, the degree of contamination is greater than one might expect, and it is difficult to know when to stop pumping and start sampling. What level of filtrate contamination in the in situ fluid is tolerable? We propose a procedure for enhancing the value of the data derived from a particular open-hole wireline formation tester by quantitatively evaluating in real time the quality of the fluid being collected. The approach focuses on expanding the display of the spectroscopic data as a function of time on a more sensitive scale than has been used previously. This enhanced sensitivity allows one to confidently decide when in the pumping cycle to begin the sampling procedure. The study also utilizes laboratory determined PVT information on collected samples to form a data set that we use to correlate to the wireline derived spectroscopic data. The accuracy of these correlations has been verified with subsequent predictions and corroborated with laboratory measurements. Lastly, we provide a guideline for predicting the pump-out time needed to obtain a fluid sample of a predetermined level of contamination when sampling conditions fall within our range of empirical data.

Micropalaeontological biostratigraphy of the Magnus Sandstone Member (Kimmeridgian-Early Volgian), Magnus Field, UK North Sea

Abstract The micropalaeontological biostratigraphy of the Magnus Sandstone Member of Kimmeridgian-Early Volgian age is described for the first time using data from 27 Magnus Field wells (blocks 211/12a and 211/7a). Despite extensive re-sedimentation within the Magnus Sandstone Member turbidite reservoir, a consistent sequence of nine bioevents is recognized field-wide. These include both regionally extensive bioevents and localized extinction and acme bioevents. The microfaunas are documented and key taxa, which include numerous radiolarian species, are described and figured. The bioevent scheme provides the basis for the chronostratigraphic and genetic sequence stratigraphic subdivision ( sensu Galloway) of the Magnus Sandstone Member. It allows the recognition and biostratigraphic calibration of three maximum flooding surfaces (MFS) which in ascending stratigraphic order comprise: the pre-Magnus Sandstone Member top J62-basal J63 ‘ Eudoxus ’ of Partington et al. (upper limit of the ‘Lower Kimmeridge Clay Formation’); the intra-reservoir top J63-basal J64 ‘ Autissiodorensis ’ (‘B Shale’); and the supra-reservoir top J64-basal J66 ‘ Hudlestoni ’ (upper limit of the ‘H Unit’). The erection of a field-specific biostratigraphic framework that characterizes and discriminates between the individual shales associated with the Magnus Sandstone Member has impacted on reservoir modelling, primarily in the area of fluid pressure distribution, where shales such as the ‘B Shale’ and those of the ‘F Unit’ form significant intra-reservoir pressure barriers, placing sands in pressure isolation. Using a bioevent-constrained well correlation in the central field area this pressure compartmentalization is illustrated with reference to repeat formation tester tool (RFT) pressure depletion data. At a broader scale, the biostratigraphically-defined ‘time slices’ are used in conjunction with three-dimensional (3D) seismic data to model Magnus Sandstone Member submarine fan evolution, which is interpreted in terms of three main depositional phases: (1) a latest Kimmeridgian (J63) single submarine fan lobe with a depocentre in the mid-field, sourced from the northwest and displaying laterally confined, fault-controlled canyon-fill; (2) Early Volgian (J64 lower) bilobate accretion with two depocentres forming either side of the N-S-trending Brent High; and (3) late Early Volgian (J64 upper) as before but with the southward migration of the northern lobe depocentre, with fault confinement. Micropalaeontology has also been used at the well site in the Magnus Field where it has influenced drilling operations in ‘real time’. The primary role to date has been the precise picking of casing points above high-pressured or low-pressured sands (e.g. ‘A Unit’) and calibration of supra-reservoir angle-build in deviated wells. It is concluded that the application of biostratigraphy to integrated reservoir description has considerably enhanced our knowledge of submarine fan heterogeneity in Magnus, which has in turn led to more effective reservoir management and an extended production life for the field.

Consistency Check and Reconciliation of PVT Data From Samples Obtained With Formation Testers Using EOS Models

Summary Accurate description of hydrocarbon fluids is critical to field development planning including facilities design, recovery efficiencies, secondary recovery processes, and remedial procedures for intervention. Despite this large impact of fluid characteristics on field development, generally a small number of downhole fluid samples are collected. Often they are not representative of the reservoir fluid for a variety of reasons. These include phase separation caused by drawdown during sampling and leakage during recovery and transport. In this paper we show the utility of a routinely reported piece of data, namely, the tool opening pressure, in a quantitative manner to check the quality of the sampled fluid. The condition of the fluid is modeled by performing an isochoric flash experiment that mimics the actual conditions. A significant discrepancy in modeled and real opening pressure data often suggests leakage. When this method is used, the fluid samples may be approximately reconstructed, multiple fluid samples from the same reservoir may be reconciled, and a consistent phase behavior of the fluid may be determined.

Application of High-Resolution Sequence Stratigraphy to Northwest Hutton Field, Northern North Sea: Implications for Management of a Mature Brent Group Field

The Middle Jurassic Brent Group reservoirs in Northwest Hutton comprise shallow-marine, marginal-marine, and coastal-plain reservoir sandstones of both channelized and sheet geometries. The connectivity and production characteristics of these sandstones can be predicted through the application of high-resolution sequence stratigraphic correlation techniques. The Broom Formation overlies a basal Brent sequence boundary and is a lowstand to transgressive systems tract tidal-estuarine complex. The overlying Rannoch Formation comprises shoreface sands that represent a highstand systems tract. The overlying Etive Formation is a multilayer fluvial to estuarine channelized system of near fieldwide development interpreted as incised valley fills. The superjacent Ness Formation is genetically related to the Etive and is the main oil-bearing interval over much of the field. The Lower Ness comprises mouth-bar parasequences and is interpreted to be a transgressive systems tract to the Etive lowstand. The Upper Ness is a nonmarine delta plain succession, interpreted as a highstand systems tract. Upper Ness channel sands typically correlate between several wells and are oriented west-east. An interval of widespread, stacked channels indicates a change in drainage orientation and is related to a high-frequency relative sea level fall. The uppermost reservoir unit is the Tarbert Formation, related to a further major sequence boundary. Original repeat formation tester data support a stratigraphically well- connected reservoir model. Compartmentalization exists and is due to stratigraphic layering (laterally persistent mudstones creating low vertical permeability) and variable dimensions of channels and valley fills.

Distribution of alkali and alkaline earth ions in the near well-bore region after invasion of mud filtrate

A modified equation for the Gapon selectivity coefficient was found to fit ion-exchange isotherms of kaolinite and montmorillonite for divalent/monovalent cation exchange. This equation was used to predict the distribution of divalent/monovalent cations in the region near the well-bore after infiltration of mud. A field test was carried out to study sorption/desorption reactions on sedimentary rocks after the infiltration process. This test used a tracer technique in which mud was tagged with tritiated water during drilling an oil well. The fraction of mud filtrate water was determined from the measured fraction of tritiated water. The ionic composition of the pore water sampled by using a kind of formation tester equipment (FTE), is considered as a survey of the ionic distribution of the invaded ionic substituents. Data from the field test confirm the predicted values of divalent cations sorbed/desorbed on the sedimentary rocks after the infiltration process. Distribution of monovalent/divalent cations in the near well-bore region is important for the open-hole log interpretation used for reservoir description.

Use of tracers for mud filtrate and completion fluid invasion studies

The objectives of this work are (1): to study sorption/desorption of mud filtrate ions near the wellbore region by using water sampled with a formation tester equipment (FTE); (2) to study sorption/desorption of ions in the mud filtrate and the completion fluid by monitoring the ionic composition of produced water; (3) to determine the fraction of mud filtrate and completion fluid water in produced water; and (4) develop a suitable and safe tracer method. A tracer method was developed to measure sorption/desorption of various ions infiltrating the reservoir during drilling and completion of a well. Tritiated water (HTO) was used to tag the mud filtrate and bromide ion (Br−) to tag the completion fluid. The measurements are based on analysis of FTE and produced water samples. The ionic concentrations observed are compared with corresponding “no sorption/desorption” concentration values determined theoretically. Special attention is paid to the “tracer diagram” of an open well, because a “no sorption/desorption curve” can be expressed in a straight line in a linear coordinate system. Observed deviations from these curves show that sorption/desorption processes have taken place. The tracer method presented was useful to determine the distribution of ions in the pore-water/sedimentary rock system near the wellbore.

Influence of an Invaded Zone on a Multiprobe Formation Tester

Summary When an oil or gas well is being drilled, some of the borehole fluid (mud filtrate) leaks into the formation, displacing the native reservoir fluid. This creates an invaded zone around the wellbore. The invading fluid will generally have a mobility and compressibility that differ from the formation fluid. The presence of the invaded zone will affect the pressure transients measured by a formation tester. In this paper, a model that includes an invaded zone is presented together with an analysis of its effect at each of the probes of a multiple probe formation tester. The results show that the properties of the invaded zone dominate the pressure transient measured at the sink probe, strongly influence the transient at the horizontal probe, and only modestly affect the vertical probe transient. A suggested modification to the current interpretation procedure (which does not consider the invaded zone) for determining the horizontal and vertical mobility is also presented. The application of this modified procedure is discussed using a model example.

A Laboratory Investigation of Permeability in Hemispherical Flow With Application to Formation Testers

Summary We use borehole and laboratory measurements with a probe to obtain local permeability estimates. Under ideal conditions sufficiently far from the probe, the flow induced is hemispherical. We describe an experimental apparatus that can flow fluids through a probe under isotropic confining stresses and present an analysis to deduce the optimal dimensions of a finite cylindrical rock to simulate hemispherical flow like that in a semi-infinite medium. We derive equations for permeability interpretation of laboratory measurements. We made pressure measurements on a number of synthetic and natural rocks as functions of confining stress, probe size, flow rate, and flow direction. For synthetic rocks, the calculated permeability shows little dependency on these factors. For natural media, however, flow direction appears to have a major effect at high rates that increases with decreasing probe size. On the basis of these data, we propose a fines-migration mechanism. As expected, permeabilities show a hysteretic dependence on confining stress. Hemispherical flow measurements with homogeneous porous media indicate that fluid injection would yield permeability close to the true value. Furthermore, sequential injection of multiple phases shows that endpoint effective permeabilities may also be obtained.

Predicting Gas, Oil, and Water Intervals in Niger Delta Reservoirs Using Gas Chromatography

Formation evaluation experts usually have little difficulty in interpreting wireline logs to assess the type of reservoir fluid (oil/gas/water) in sand-shale sequences. This assessment is usually accomplished by a combination neutron-density tool that detects low hydrogen and low electron densities typical of gas zones, and the repeat formation tester (RFT), which uses both the pressure gradient and sample acquisition techniques to evaluate reservoir fluid. In the Niger Delta, however, many of the sands exhibit a poor neutron-density response to gas, and RFT testing has been largely eliminated because poor hole conditions commonly result in stuck tools. Oil fingerprinting of residual hydrocarbons from sidewall core extracts can provide an independent means of identifying eservoir fluid type. In conjunction with the Nigerian National Petroleum Company, we completed numerous chromatographic analyses on solvent extracts of sidewall core samples from various wells in the Mefa field, offshore west Niger Delta. Oil fingerprints of sidewall core extracts clearly reflect the type of hydrocarbons in the reservoir. Fingerprints of oil-saturated sands are typical of topped (C15+) whole oils, whereas fingerprints of hydrocarbons extracted from the gas-dominated sands show an abbreviated hydrocarbon distribution more typical of gas condensates. Fingerprints of extracts from water-productive intervals show a further abbreviated signature, suggesting that higher molecular weight hydrocarbons did not migrate into these intervals. These signatures are distinct and intact despit poor sample preservation due to prolonged storage of up to 3 yr. Additional applications of this technique include the reevaluation of older wells that lack modern wireline measurements, but have sidewall or conventional core material available, and in thin or low-permeability sands that may not yield definitive RFT or wireline-log responses. Application potential for this technology is worldwide and includes the Gulf Coast of the United States, Canada, Indonesia, and Papua New Guinea.