Residual Hydrocarbon Saturation Research Articles

An enhanced oil recovery technology applicable to kazakhstan reserves with highly viscous oils

The subject of discussion of the article below is polymer flooding as an EOR (enhanced oil recovery) technique considered here within the context of Kazakhstan’s depleted oil-fields exploitation. The underlying factor for considerable residual hydrocarbon saturation observed in the productive reservoirs of the majority of Kazakhstan’s oil fields connected with their stratified heterogeneous structures. Such kind of Oil Reservoirs require additional developments comprising new technologies promoting enhanced oil-recovery. Keywords: viscosity; inhomogeneity; polymer flooding; polyacrylamide; degree of inhomogeneity; permeability; catholyte; trim.

Assessment of Depth of Mud-Filtrate Invasion and Water Saturation Using Formation-Tester Measurements: Application to Deeply Invaded Tight-Gas Sandstones

Formation pressure/fluid measurements are impacted by mud-filtrate invasion, which may require long fluid pumpout durations to acquire hydrocarbon samples with minimal mud-filtrate contamination. However, unlike other well-logging instruments, formation testers do not have a fixed depth of investigation that limits their ability to pump out mud filtrate until acquiring original formation fluids (i.e., sensing the uninvaded zone). We use an in-house petrophysical and fluid-flow simulator to perform numerical simulations of mud-filtrate invasion, well logs, and formation-tester measurements to estimate the radial distance of invasion and the corresponding radial profile of water saturation. Numerical simulations are initialized with the construction of a multilayer petrophysical model. Initial guesses of volumetric concentration of shale, porosity, water saturation, irreducible water saturation, and residual hydrocarbon saturation are obtained from conventional petrophysical interpretation. Fluid-flow-dependent petrophysical properties (permeability, capillary pressure, and relative permeability), mud properties, rock mineral composition, and in-situ fluid properties are obtained from laboratory measurements. The process of mud-filtrate invasion and the corresponding resistivity and nuclear logs are numerically simulated to iteratively match the available well logs and estimate layer-by-layer formation water saturation. Next, using our multiphase formation testing simulator, we numerically simulate actual fluid sampling operations performed with a dual-packer formation tester. Finally, we estimate irreducible water saturation by minimizing the difference between the hydrocarbon breakthrough time numerically simulated and measured with formation-tester measurements. The examined sandstone reservoir is characterized by low porosity (up to 0.14), low-to-medium permeability (up to 40 md), and high residual gas saturation (between 0.4 and 0.5). The deep mud-filtrate invasion resulted from extended overbalanced exposure to high-salinity water-based mud (17 days of invasion and 1,800 psi overbalance pressure) coupled with the low mud-filtrate storage capacity of tight sandstones. Therefore, the uninvaded formation is located far beyond the depth of investigation of resistivity tools, whereby deep-sensing resistivities are lower than those of uninvaded formation resistivity. Through the numerical simulation of mud-filtrate invasion, well logs, and formation-tester measurements, we estimated radial and vertical distributions of water saturation around the borehole. Likewise, we quantified the hydrocarbon breakthrough time, which matched field measurements of 6.5 hours. The estimated radius of invasion was approximately 2.5 m, while the difference between estimated water saturation in the uninvaded zone and water saturation estimated from the deep-sensing resistivity log was approximately 0.13, therefore improving the estimation of the original gas in place.

Automatic Multiwell Assessment of Flow-Related Petrophysical Properties of Tight-Gas Sandstones Based on the Physics of Mud-Filtrate Invasion

Summary Petrophysical interpretation of borehole geophysical measurements in the presence of deep mud-filtrate invasion remains a challenge in formation evaluation. Traditional interpretation methods often assume a piston-like radial resistivity model to estimate the radial length of invasion, resistivities in the flushed and virgin zones, and the corresponding fluid saturations from apparent resistivity logs. Such assumptions often introduce notable inaccuracies, especially when the radial distribution of formation resistivity exhibits a deep and smooth radial front. Numerical simulation of mud-filtrate invasion and well logs combined with inversion methods can improve the estimation accuracy of petrophysical properties from borehole geophysical measurements affected by the presence of mud-filtrate invasion. We develop a new method to quantify water saturation in the virgin zone, residual hydrocarbon saturation, and permeability from borehole geophysical measurements. This method combines the numerical simulation of well logs with the physics of mud-filtrate invasion to quantify the effect of petrophysical properties and drilling parameters on nuclear and resistivity logs. Our approach explicitly considers the different volumes of investigation associated with the borehole geophysical measurements included in the interpretation. The new method is successfully applied to a tight-gas sandstone formation invaded with water-base mud (WBM). Petrophysical properties were estimated in three closely spaced vertical wells that exhibited different invasion conditions (i.e., different times of invasion and different overbalance pressures). Available rock-core laboratory measurements were used to calibrate the petrophysical models and obtain realistic spatial distributions of petrophysical properties around the borehole. This approach assumes that initial water saturation is equal to irreducible water saturation. Based on the calibrated petrophysical models, thousands of invasion conditions were numerically simulated for a wide range of petrophysical properties, including porosity and permeability. Based on the large data set of numerical simulations, analytical and machine-learning (ML) models were combined to infer unknown rock properties in each well. Mean-absolute-percent errors (MAPE) of the analytical and ML models for the estimation of water saturation in the virgin zone are 5% and 2%, respectively, while the MAPE of the analytical models for the estimation of residual hydrocarbon saturation is 10%. Synthetic and field examples are examined to benchmark the successful application and verification of the new interpretation method. Estimates of water saturation in the virgin zone using the new method are in good agreement with core-based models.

Assessment of CO2 storage potential in reservoirs with residual gas using deep learning

[Formula: see text] injection into the underlying water leg of depleted hydrocarbon reservoirs is a desirable option for carbon storage as demonstrated by existing industrial-scale storage projects in these geologic environments. This study sheds light on the effect of residual methane on the [Formula: see text] storage efficiency as a screening criterion for selecting a water-bearing zone of a depleted gas reservoir to store [Formula: see text]. Using compositional reservoir simulations, we have evaluated the impact of residual methane on the injectivity, operational pressure, and long-term [Formula: see text] trapping efficiency during injection and postinjection stage in a reservoir model representative of the so-called “HC sand” gas reservoir in the High Island 24L field located in the offshore Texas State Waters. Results suggest that the presence of residual hydrocarbon gas negatively affects [Formula: see text] residual and dissolution trapping because it enhances the injectivity and pressure management arising from the increased mobility of [Formula: see text] plume in the vicinity of the injection zone due to its mixing with the resident residual hydrocarbon gas. We further investigate the application of artificial neural network (ANN)-based proxy models for fast-track modeling of [Formula: see text] storage in geologic structures associated with depleted gas reservoirs, aiming at the prediction of [Formula: see text] trapping efficiency. We then use the developed ANN model to perform Monte Carlo simulations for quantifying the uncertainty of geologic and reservoir parameters on [Formula: see text] trapping efficiency in these formations. It becomes evident that the residual hydrocarbon saturation is a key screening criterion for the storage site selection. The developed data-driven model can offer a robust and fast tool for screening the water-bearing zone of the depleted gas reservoirs by evaluating the efficiency of [Formula: see text] storage.

Modelling shale spontaneous water intake using semi‐analytical and numerical approaches

AbstractShale matrix water intake during hydraulic fracturing is considered undesirable due to the high volume of unrestrained water loss; however, it is also rewarding because it can reduce the possibility of groundwater contamination. The water intake also plays a dual role in changing the shale production performance; water imbibition into matrix pores can dramatically reduce the effective permeability and, at the same time, might enhance hydrocarbon production by creating adsorption‐induced micro‐fractures. Quantifying the formation intake capacity and its breadth is the key to optimizing fracturing operation, flowback, and production strategy. This work entails complementary semi‐analytical and numerical analyses and investigates the effects of basic rock and fluid properties, wettability heterogeneity, and pore space connectivity on the shale imbibition characteristics. We consider a semi‐analytical formulation of the spontaneous water imbibition, together with model results and validations, and try to provide a framework to link the capillary imbibition capacity/rate to lab‐scale observations. The core‐scale measurements provide input for a sensitivity study on the matrix imbibition capacity in six shale plays in North America. The results suggest that rock permeability, hydraulic tortuosity, and initial and residual hydrocarbon saturations are among the most influential factors on the spontaneous water intake during shut‐in periods. Direct quasi‐static simulations are then conducted through a submicron tomography image of the Eagle Ford shale, and two‐phase pore‐level fluid occupancies are reconstructed during spontaneous and forced imbibition processes. According to the numerical results, the presence of continuous organic matter laminae can lower the destructive effects of water imbibition on the hydrocarbon permeability.

Saturation Modeling Under a Complex Fluid-Fill History: Drainage and Imbibition

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 188594, “Saturation Modeling Under Complex Fluid-Fill History—Drainage and Imbibition,” by H. Xian, SPE, L. Beugelsdijk, SPE, and A. Kohli, SPE, Shell; E. Fokkema, SPE, Nederlandse Aardolie Maatschappij; and A. Cense, Shell, prepared for the 2017 Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, 13–16 November. The paper has not been peer reviewed. This paper presents a saturation-modeling approach for fields and reservoirs with complex hydrocarbon-charging histories. The model resolves saturation-height functions for the primary-drainage, imbibition, and secondary-drainage equilibriums. As part of the approach, a method of evaluating the residual-hydrocarbon saturation below the initial free-water level (FWL) is proposed. The developed theory is based on the principle of capillary-pressure/saturation hysteresis on the drainage/imbibition process in a water-wet system. Introduction Many discovered oil and gas fields are found to have gone through complex fluid-fill histories where residual hydrocarbons are observed below the FWL. To add to the complexity, some of these are giant fields and are divided into compartments with varying contacts and FWLs. To model saturation-height dependencies for reservoirs in fields under imbibition equilibrium, one of the adopted practices is to use a drainage model built from core data or log data to compute the saturation starting from the original FWL contact but only calculate the hydrocarbon-in-place volumes above the initial FWL. Another common practice is to build log-based drainage models using the current FWL while ignoring the uncertainties in the transition zone from the imbibition effect. These approaches typically lead to an inappropriate estimation of the hydrocarbon saturation in the transition zone and normally require separate models for different segments of the field. In this paper, an approach is presented for modeling the core capillary-pressure imbibition and secondary drainage cycles, integrating with log-based saturation-height models, and designing a work flow for upscaling and implementation in 3D reservoir models. Imbibition and Secondary-Drainage-Model Theory Hysteresis of Saturation/Capillary Pressure and Analytical Imbibition Model Method. Modeling of saturation/capillary pressure of primary-drainage-imbibition hysteresis is more complicated than other types of hysteresis effects because its cycle is not a closed loop; the imbibition route does not end at the starting point of the primary drainage route. Fig. 1 shows the multi cycle drainage/imbibition scanning curves in mixed-wet or strongly water-wet rock systems. Saturation changes caused by the imbibition-hysteresis effect are larger at lower capillary pressures in the transition zone but become insignificant over the higher capillary pressures across the main nonwetting-phase column. The primary-drainage capillary pressure can be measured by high-pressure mercury injection, porous plate, and centrifuge. Spontaneous imbibition can be measured only by use of the porous-plate technique or by use of an Amott cell. The forced imbibition part of the imbibition capillary pressure can be measured by porous plate and centrifuge.

Assessment of CO2 residual trapping in depleted reservoirs used for geosequestration

Carbon capture and sequestration technology is a major approach developed to mitigate the amount of greenhouse gases released into the atmosphere. Technically, depleted oil and gas reservoirs are one of the feasible subsurface geologic media for large-scale carbon dioxide (CO2) storages. Trapping mechanisms during and after CO2 injection in geologic formations ensure the long-term safety and security of a storage task. However, depending on characteristics of geologic sites and subsurface conditions, different trapping mechanisms may come to play during sequestration, among which residual trapping is by far the most efficient one in a short-term scale. Although there have been many experimental and numerical studies carried out in the past years to evaluate this trapping potential prior to injection, there is not any field-scale approaches developed to assess CO2 residual trapping at the depletion stage of oil and gas reservoirs. The aim of this paper is to present a method for residual trapping assessment of CO2 storage sites by considering related and effective constraints such as residual hydrocarbon saturation, interfacial tension, pore geometry, and wettability. An analytical method based on a adjustment factor was proposed which could be used to determine the residual CO2 saturation/residual trapping for different rock types having different wetting characteristics. Two wells out of a total number of 20 wells (mostly depleted) from the largest gas field in Malaysia were considered as part of this study to show how the proposed method can be executed in the field scale for determination of the residual trapping ability of the reservoir. The results obtained indicated that the average residual CO2 saturation by the proposed method is around 26% and 27% for Well A and Well B, respectively. Thus, the maximum volume of CO2 residual trapped could be approximately 0.96 Tscf or 0.97 Tscf of the effective pore volume (excluding 30% Sgr), based on the average saturations estimated from the data of Well A and Well B. The results were validated both experimentally and numerically where it was found that the proposed method and three phase core flooding experimental data are in good agreement, indicating a strongly water wet system. However, more experimental studies on the core samples taken from the same field are required to further validate the results before fully implementing CO2 storage in the site.

Implication of seismic and borehole data for the structure, petrophysics and oil entrapment of Cretaceous-Palæocene reservoirs, northern Sirt Basin, Libya

The geophysical analysis of 27 seismic sections with well logging data and geological information gathered from 56 deep wells covering the study area of northern Sirt Basin proved to be valuable for evaluating its structural setting and oil potentialities. This study aims to throw more light on the structural, stratigraphical and petrophysical characteristics that control two of the potential hydrocarbon reservoirs of Sirt Basin, the Waha Formation of Upper Cretaceous age and the Zelten Formation of Upper Palæocene age. Also, it presents an exploration method that promotes the existing leads and shows how to continue finding additional reserves and continue developing these prospective formations. This comprehensive study reveals that the overall tectonic setting of the area is controlled by northwest-southeast-trending faults formed since the Early Palæozoic times. These faults gave rise to division of the study area into different horsts and grabens with erratic distribution of the studied formations. This pattern may relate to variations in the relationship between withdrawal of material from the underlying upper mantle and the fault movements. The Palæozoic and Mesozoic rocks show stronger lateral and vertical variations in thickness and lithology than those of overlying Tertiary and Quaternary sediments. In addition, the geophysical studies reflect the mixed lithological nature of the studied formations, which greatly influence the total and effective porosity and permeability index, which consequently controlled the percentages of movable and residual hydrocarbon saturations. Moreover, additional information and results concerning the structure, reservoir petrophysics, hydrocarbon accumulation and entrapment were achieved and represented on a number of cross-sections and contour maps.

Invasion percolation and secondary migration: experiments and simulations

Experiments have been carried out to study the displacement of wetting fluids by immiscible non-wetting fluids in quasi-two-dimensional and three-dimensional granular porous media. These experiments included a systematic investigation of the effects of gravity acting on the density difference between the two fluids. The simple invasion percolation model provides a surprisingly realistic simulation of the slow fluid–fluid displacement process in the absence of gravity, and a simple extension of the model can be used to simulate the most important features of gravity stabilized and destabilized fluid–fluid displacement processes. The dimensionless Bond number Bo (the ratio between buoyancy forces and capillary forces on the pore scale) can be used to compare experiments and simulations carried out using different (geometrically similar) porous media, different fluid–fluid interfacial tensions and different fluid densities. The complex patterns generated by gravity stabilized and gravity destabilized fluid–fluid displacement processes can be described in terms of a pattern of blobs of size ξ that have a fractal structure on length scales l in the range ϵ≤ l≤ ξ, where ϵ is the characteristic porous medium grain size. The blob size ξ is related to the Bond number by the simple scaling relationship ξ∼ Bo − ν/(1+ ν) , which was first derived by Wilkinson (1984, 1986) for gravity-stabilized displacement. Here, ν is the percolation theory correlation length exponent ( ν=4/3 in two-dimensional systems and ν≈0.88 in three-dimensional systems). The experiments and simulations have been extended to include fluid–fluid displacement in fracture apertures and the effects of flow of the wetting fluid under the influence of a hydraulic potential gradient. These experimental and simulation results have important implications for our understanding of secondary migration. They indicate that the residual hydrocarbon saturation in the enormous volume of porous sedimentary rock (carrier rocks) between the hydrocarbon source and the reservoir can be very low, thus allowing significant quantities of oil and gas to reach the reservoir. Simulations have been carried out to explore the effects of heterogeneities on gravity destabilized fluid–fluid displacement processes and fluid–fluid displacement in fracture apertures. However, the structure of the carrier rocks is highly dynamic on the time scales over which secondary migration takes place (of the order of 10 8 years, in many cases). A better understanding of the pore structure of the carrier rocks and its dynamics on long time scales is needed to more accurately model secondary migration.

Modeling Free Product Migration and Recovery at Hydrocarbon Spill Sites

AbstractThe numerical model ARMOS, which simulates areal flow of water and light hydrocarbon in an unconiined aquifer, isdescribed. Based on the assumption of local vertical equilibrium, area! flow equations for water and hydrocarbon are derived which exhibit reduced dimensionality and nonlinearity. A finite‐element method is used to solve the water and oil equations using an efficient semidecoupled approach. Input required by the model includes area! boundaries, elevations of the aquifer lower boundary, and initial water and hydrocarbon levels in monitoring wells. Soil and fluid properties include hydrocarbon density, viscosity and surface tension, saturated hydraulic conductivity, van Genuchten air‐water capillary pressure curve parameters, and the maximum residual hydrocarbon saturations in the saturated and unsaturated zones. Fluid heads or fluxes may be specified on the domain perimeter and pumping rates are prescribed at recovery wells. The water pumping rate is automatically limited when drawdown reaches a pump‐off set point (or the screen bottom), and hydrocarbon recovery is limited when well hydrocarbon thickness becomes zero. Model output includes water and hydrocarbon levels in monitoring wells, cumulative product recovery, and free and residual hydrocarbon volumes in the soil. A hypothetical problem involving optimization of free product recovery and a field application of the model to a large pipeline leak are described.

An experimental investigation of waterflooding of gas condensate reservoirs and their subsequent blowdown

The phase and flow behaviour of water, gas and condensate in pores at reservoir conditions have been visually investigated using glass micromodels, with the pore dimensions and pore geometry of the micromodels being varied between tests. The displacement of hydrocarbons, both above and below the dewpoint, by the advancing water was studied. The model at residual hydrocarbon saturation was depleted and the remobilisation behaviour of the trapped gas-condensate phases was investigated. Preliminary core-flooding results obtained at conditions similar to the micromodel tests confirm the observed phenomena. The micromodel investigations has enabled the mechanisms of water encroachment in gas-condensate reservoirs to be visualised at pressures above and below dewpoint, and has highlighted the differences between flow in this system and the more conventional three-phase flow processes. The continuity of condensate throughout the pore space results in its efficient displacement ahead of encroaching water. Condesate recovery is strongly affected by the rate of advancing water and the distribution of condensate in the pores, with the residual gas-condensate saturation being dependant on the water advancement rate and degree of pore heterogeneity. The extent of the isolation of residual gas-condensate pockets in pores determines the increase in residual hydrocarbon saturation required for gas remobilisation by depletion. This paper explains some ambiguities in the residual hydrocarbon and its remobilisation as recently reported in literature, and the results should assist in improving our understanding of gas-condensate recovery and hence in the management of gas-condensate reservoirs.

Distribution of Facies, Depositional, and Diagenetic History of Knowles Limestone (Cotton Valley Group-Late Jurassic), De Soto Parish, Louisiana: ABSTRACT

The Knowles Limestone in northwestern Louisiana was deposited in a warm, very shallow sea on a carbonate ramp. Depositional and diagenetic environments suggest a tropical to subtropical humid climate. Four major depositional settings were present: a restricted tidal flat, a restricted to open lagoon, a reef flat, and a reef core. Restricted tidal-flat deposits include algal-laminated mudstones, wackestones, and bindstones; dolostones; and mudstones where algae and mollusks were abundant with minor echinoderms and bryozoans. Mostly wackestones and rarely packestones were deposited in the lagoon. Oysterlike bivalves and calcareous algae were very common in the lagoon, with coral, hydrozoans, echinoderms, and bryozoans occasionally abundant. Bioturbation and dolomitization are very common in the tidal flat and lagoonal deposits. Principal contributors to the reef framework were corals, stromatoporoids, and encrusting algae which reflect ecological succession. In the reef-flat environment, oncoidal-skeletal wackestones to packstones were deposited. Rarely, they attained bindstone fabric encrusted by codiacean algae. Reef development was ended by prograding tidal-flat deposits. The Knowles sediments display diagenetic signatures from marine phreatic, meteoric phreatic, fluid mixing, subaerial, basinal fluid expulsion, and tectonic stages of diagenetic alteration. Among the Knowles sediments, supratidal dolostones possess best porosity and permeability, but residual hydrocarbon saturation is nil.

Scanning Electron Microscopy and Core Analysis for "Mini" CO2 Flooding Operations in the Hospah Formation of the Miguel Creek Field, McKinley County, New Mexico

Abstract A combined laboratory evaluation that included scanning electron microscopy (SEM), energy dispersive spectrometry (EDS), X-ray diffraction, petrography, and core flow/permeability damage analysis was performed on core samples from the Hospah formation of the Miguel Creek field, McKinley County, NM. The objective of this study was to determine what type of recovery method would be the most beneficial and economical for a pilot five-spot, 8-acre plot. The geologic evaluation of the core samples indicated tremendous lithologie differences in this formation. The rock types contained appreciable amounts of migrating clays (kaolinite and illite). Various degrees of pyrite, total clay content, and residual hydrocarbon saturation also were observed. According to the operator, a conventional waterflood operation attempted during 1974–76 proved unsuccessful. This study indicates that the most likely reason was migratory fines. A foam fracturing technique also was attempted in June 1980 in the Miguel Creek field, with similar negative results. The conclusions from this study suggested that the use of a clay-stabilizing surfactant preflush in a "mini" CO2 waterflood could be an advantageous method of controlling migrating fines and swellable clays.

Pulsed Neutron Capture Log Evaluation Using Synthetic Base Logs (includes associated papers 10920 and 10939 )

The evaluation of recompletion opportunities using pulsed neutron logs ismade easier by preparing predictive synthetic logs using openhole log data.Wellsite personnel can assess drainage quickly by comparing the actual logwith the synthetic expected response, thus avoiding time-consuming trialcalculations. Introduction The pulsed neutron capture (PNC) log has proved tobe a valuable production surveillance tool for theU.S. gulf coast environment since its introduction in1962. In this geographic area, more than 900 PNClogging runs have been made in producing Shell wellsalone. We have come to rely on this tool as a reliableaid for basing many of our remedial andrecompletion decisions.In conventional PNC log evaluation, watersaturation (Sw) calculated from openhole logs iscompared with Sw computed from the cased-holePNC log. Drainage is indicated when a statisticallysignificant difference in Sw is observed. Althoughthis technique is a practical procedure, the calculations can be time-consuming and subject tohidden errors.A nearly foolproof method of assessing drainagefrom PNC log data is the time-lapse technique. Inthis method, a base PNC log is run early in the life of the well, preferably before water production begins.When subsequent drainage requires assessment, asecond log is run and compared with the first. If thewellbore environment (production equipment, annular fluids) has not changed greatly, differencesbetween the logs can be caused only by reservoir fluidchange. The problem with this approach, of course, is the expense and practicality of building a completebase-log inventory. It usually is not justifiable.This paper presents a simple computer techniquefor creating synthetic base PNC logs using theoriginal openhole log information. Offering many ofthe advantages of actual base-log data, the computer technique is easy to use and surprisingly accurate. Inaddition, synthetics can indicate quickly whether aPNC log can be interpreted reliably under adverseconditions. This can help the engineer choose morewisely among evaluation alternatives before a loggingcommitment is made. Example Fig. 1 shows an example of a synthetic pulsedneutron log made using this technique. An openholegamma-ray induction log is displayed on the left;cased-hole PNC curves (synthetic and actual) areshown on the right. Note the capture cross sectioncurve of a Schlumberger TDT-K (TM) log ("Sigma log"-the dashed curve) run 1 year after the well wasdrilled and cased. This curve is flanked by two logtraces, Sigma i and Sigma d, generated by the computer process usingopenhole logs. The Sigma i curve represents a "synthetic"PNC sigma curve at initial conditions. It shows whatan actural PNC base log would have looked likebefore the zone was drained. The d curve representsthe fully drained condition, in which the zone is totally water saturated. This curve represents the endpoint of drainage.(Actually, this condition will neverquite be reached since some residual hydrocarbonsaturation always remains after waterflood inwater-wet reservoirs.) JPT P. 667＾

Well Formation Characterization by Residual Hydrocarbon Analysis

JFT Forum articles are limited to 1,500 words including 250 words for each table and figure, or a maximum of two pages in JPT. A Forum article may present preliminary results or conclusions of an investigation that the author wishes to publish before completing a full study; it may impart general technical information that does not warrant publication as a full-length paper. All Forum articles are subject to approval by an editorial committee. Letters to the editor are published under Dialogue, and may cover technical or nontechnical topics. SPE-AIME reserves the right to edit letters for style and content. Introduction Information supplied by current wellbore evaluation methods often is insufficient for optimum well completion. Recent developments indicate that additional data useful for this application may be obtained from the composition of residual hydrocarbons in drill cuttings. As early as the mid-1950's, Smith and Evans demonstrated that residual hydrocarbons could be used to characterize some geologic formations. The general principles involved later were extended by Reed and Warren and Scrima to oil shale formations using pyrolysis techniques and thermal chromatography. In pyrolysis techniques and thermal chromatography. In 1974, Baker expanded their work to include petroleum source-rock evaluations. Other investigators during this period experienced only limited success in modifying the technique for use in wellbore evaluations. This paper describes a pyrochromatographic analysis that has proved useful when characterizing the producing potential of certain types of wells. potential of certain types of wells. Description of Method Our method involves the premise that not all hydrocarbons in bits of formation rock are lost when these samples are brought to the surface during normal drilling procedures. Phase behavior and formation permeability procedures. Phase behavior and formation permeability phenomena responsible for residual hydrocarbons in these phenomena responsible for residual hydrocarbons in these samples have been well documented. Relationships between residual hydrocarbon saturations and formation production potential also have been well established. Our method potential also have been well established. Our method uses these relationships to correlate characteristics of test sample hydrocarbon with well production potential. The analyzer used was composed of a low dead-volume pyrolysis unit attached directly to a flameionization gas pyrolysis unit attached directly to a flameionization gas chromatograph. A large pyrolysis chamber (1 m1 in volume) was developed to allow the testing of larger, more representative formation samples. Fig. 1 - Carbon-number distribution for nonproductive formation. Fig. 2 - Cumulative percent curve for nonproductive formation. JPT P. 118

A Mathematical Model of the Hawkins Woodbine Reservoir

A mathematical model of the Hawkins Woodbine reservoir was developed to predict individual tract and total fields reserves. Each of the field's predict individual tract and total fields reserves. Each of the field's 362 fault-block sand members was considered a uniform pressure tank, and contact movement was predicted with volume-depth curves. Adequacy of the model was verified by comparing actual and predicted contact movement rates for pre-unit operations. Introduction The objectives of the model-development phase of the Hawkins Unitization Engineering Study were to estimate individual tract and total primary field reserves and to appraise additional recovery possible with unitized operations. In addition, the Engineering possible with unitized operations. In addition, the Engineering Subcommittee recognized that if it developed a computerized field model to meet those objectives, it would have a tool that later would prove valuable in planning unit operations, including forecasts of production, drilling, and recompletion needs for maximum recovery and reservoir control. The need for the study arose when the Hawkins Unitization Working Interest Owners Committee requested the Engineering Subcommittee to estimate reserves. The owners believed that an acceptable field unit participation formula would allocate primary reserves to each tract plus a fair share of the increased recovery resulting from unitized operations. The Engineering Subcommittee recognized that the Hawkins field (having 45 fault blocks, 10 sand members, 327 tracts, and nearly 500 producing wells) would be difficult to model in necessary detail with a conventional finite-difference simulator. A three-phase, three-dimensional simulator would have been necessary for each of the 362 fault-block sand members, most of which are in partial communication with others. The subcommittee also partial communication with others. The subcommittee also recognized that a highly simplified, total-field modeling procedure probably would not provide the necessary detail for individual probably would not provide the necessary detail for individual tract reserves. Accordingly, the subcommittee chose the middle ground. It developed a model that included the detail of each well and each fault-block sand member, but avoided the detailed fluid-displacement calculations of a three-phase, three-dimensional finite-difference reservoir simulator. The model treats each fault-block sand member as a uniform pressure tank. Dimensionality is introduced with a volume-depth pressure tank. Dimensionality is introduced with a volume-depth curve for each sand member. Some areas of the field produce by water drive, others by gas drive, and some by depletion (solution-gas) drive. Certain areas contain only oil, some have gas and oil, and others contain only gas. To handle this wide variety of conditions, residual hydrocarbon saturations for the various drive mechanisms were input in the model, from which recovery efficiencies were determined. The model calculates new fluid-contact positions at the end of each year, using material balances on calculated fluid influxes and effluxes and volume-depth curves. The remainder of this paper describes the modeling procedure in a general way. There is as little reference as possible to specialized, one-of-a-kind challenges offered by Hawkins field and little mathematical detail. This approach reflects our belief that the modeling procedure we describe generally is applicable to geologically complex, multidrive reservoirs. Description of Reservoir Model In this section, we will describe our modeling procedure aided by a logic flow chart (Fig. 1). JPT P. 1545

Multiple Phase Behavior in Porous Media During CO2 or Rich-Gas Flooding

Mixing oil with high-ethane-content hydrocarbon gases or CO2 can produce multiple liquid phases and an asphaltic precipitate in low-temperature reservoirs. The residual saturation that occurs in a reservoir displacement is not significant from a recovery standpoint, but may produce three-phase relative permeability effects that reduce injectivity produce three-phase relative permeability effects that reduce injectivity and, thus, oil recovery rate during alternate gas-water injection. Introduction Multiple-contact miscible gas flooding has the potential for economically recovering a significant amount of incremental oil over that recoverable by conventional waterflooding. Under appropriate reservoir pressure and temperature conditions, rich gas or carbon dioxide will miscibly displace the oil it contacts. Water is injected alternately with the gas to decrease the mobility ratio and, thus, improve the sweep. One such project using rich gas in a West Texas reservoir has been described previously. However, unanticipated reduction in water injectivity occurred after injection of the first batch of rich gas, and indications were that the problem existed in depth within the reservoir and was not just a wellbore problem. Harvey et al. present the results of field studies that led to the work presented in this paper. Native-state reservoir core tests showed that the injectivity reduction could be caused by a residual oil saturation of a few percent of pore volume behind the rich-gas bank. A small amount of residual oil resulted in unusually high trapped gas saturation and a resulting decrease in water relative permeability. permeability. A small residual oil saturation and, hence, a lowered water injectivity, could arise in the field if oil was bypassed because of small-scale reservoir rock heterogeneities or if the rich gas did not completely displace all the oil contacted. Factors that produce incomplete displacement of contacted oil are presented. PVT cell data are presented that show the occurrence of PVT cell data are presented that show the occurrence of two liquid phases and an asphaltic precipitate when high-ethane-content rich gas and reservoir oil are mixed at reservoir conditions. Core tests are described showing that the formation of multiple phases results in a residual hydrocarbon saturation during displacement. Similar but less detailed studies of a CO2-oil system are also presented. Other authors, observed multiple liquid-phase presented. Other authors, observed multiple liquid-phase phenomena with some miscible gases and West Texas phenomena with some miscible gases and West Texas oils, but did not evaluate the effect on oil displacement. Windowed Cell Tests Procedure Procedure The general procedure used was to place the driving gas into a variable-volume windowed cells that was held at the reservoir temperature. The driving gases used were rich gas and CO2. A known amount of recombined reservoir oil was combined with the driving gas in the cell. A phase distribution test starting at a high pressure (usually 4,000 to 8,000 psi) was performed on this oil-driving gas mixture. This test consisted of a constant-composition expansion, during which the total volume of the cell and the distribution of the phases in the cell were measured at a known pressure. Upon completion of the phase distribution test, additional oil was introduced into the cell and another phase distribution test was performed. These tests, which were designed to simulate mixtures in the driving gas-rich region of all possible oil-driving gas mixtures, were terminated when sufficient oil had been added to dissolve all the driving gas in the cell. Any mixtures containing additional oil would have bubblepoint pressures that decrease regularly down to the saturation pressure of the recombined oil. JPT P. 1171

Oil Migration: ABSTRACT

Physical analysis of oil migration through a water-saturated, hydrophilic, porous sediment suggests the following mechanisms of migration: (1) continuous-phase flow, (2) colloidal dispersion in water, and (3) molecular solubility in water. The first mechanism, continuous-phase flow, is a major factor in controlling the movement of oil through porous reservoir rocks, the migration of oil into traps, or leakage of oil out of traps. Relatively high saturation of hydrocarbons (15-25 per cent of pore volume) must exist to create the continuity of the oil phase necessary for migration by this mechanism. The relatively low residual hydrocarbon saturations observed in many shales considered as probable source beds suggest that migration by this mechanism has not occurred therein. The second mechanism, colloidal dispersion in water, appears to be a major factor in controlling the primary migration of oil out of many typical source beds. These migrating colloids may vary from the partially reduced organic complexes found colloidally dispersed in sea water and sea-bottom muds to oil solubilized by naturally occurring soap micelles or other solubilizing agents. If this mechanism has occurred in a shale, the organic content of the shale source bed may be low, and the residual hydrocarbon content in per cent of pore volume may be almost nil. Two primary requirements for the operation of this second migration mechanism are the following. 1. The source-bed mineral surfaces must be hydrophilic. Experimental evidence indicates that the predominantly sodium-based mineral surfaces found in a normal marine sediment are generally hydrophilic and, therefore, could be source beds; whereas the predominantly calcium-magnesium-based mineral surfaces of many non-marine sediments may commonly be oleophilic and, consequently, probably are non-source beds. 2. The organic colloid, soap micelle, or other solubilizing agent must be stable and mobile within the source bed and must become unstable, immobile, or dissociated somewhere End_Page 1770------------------------------ within the reservoir bed. The flocculation or dissociation of these colloids appears to be greatly affected by the Donnan-equilibrium-controlled anion-exclusion and cation-absorption properties of high-electrical-charge-density materials such as shales. When the migration is terminated by either dissociation or flocculation, the resulting finely dispersed unstable organic particles or oil droplets will start to aggregate. Consequently, buoyancy will cause them to rise (or fall) through the water phase to the top (or bottom) few inches of the porous reservoir. If the oil or oil-forming material accumulates in the top few inches of the reservoir bed in sufficient concentration to subsequently produce extensive oil-phase continuity, then additional migration by the continuous-phase flow mechanism can occur. The third mechanism, molecular solubility in water, may be a significant factor in selectively transporting certain hydrocarbon fractions and thereby modifying the oil characteristics. If only the first mechanism were operative, source beds should be detectable by their high residual hydrocarbon content. If the second mechanism were commonly operative, such source beds could not be identified simply by measuring the residual oil saturation; and if source beds of this type are throughout most marine sedimentary sections, the limited occurrence of major oil production must be related to conditions required for continuous entrapment and preservation of oil since the time of origin. The entrapment of oil is primarily controlled by the first mechanism--continuous-phase flow. Therefore, a critical evaluation of this mechanism under both hydrodynamic and hydrostatic conditions throughout the geologic history of an area is recommended for finding both broad oil provinces and specific oil fields. End_of_Article - Last_Page 1771------------