Original Hydrocarbon In Place Research Articles

Numerical Evaluation of a Novel Slot-Drill Enhanced Oil Recovery Technology for Tight Rocks

Summary Enhanced oil recovery (EOR) is essential in shale/tight formations because primary recovery typically produces less than 10% of the original hydrocarbon in place. This work presents a novel “slot-drill” EOR (SDEOR) technology, which involves injecting gas through a horizontal fracture that is cut into the formation near the top of the reservoir (using a tensioned abrasive cable mounted to the drillstring) and producing oil from a second slot-drilled horizontal fracture near the bottom of the reservoir. A robust 3D projection-based embedded discrete fracture model (pEDFM; EDFM) is used to model the natural fractures in these slot-drilled unconventional oil reservoirs accurately and efficiently. Connectivity and uncertainty analyses are performed to determine the percolation threshold, where natural fractures influence hydrocarbon production appreciably. The results of this work indicate that the proposed technology can yield over a threefold increase in oil recovery relative to the cyclic gas EOR (CGEOR) method. This simulated recovery is high regardless of the presence of natural fractures or the type of gas/solvent injected (such as CH4, N2, CO2, and flue gas). The simulation results also indicate that the continuous gas injection, higher relative oil permeability, and the role of gravity-drainage are the main reasons why the oil recovery from the SDEOR is three times that from the CGEOR method. In conclusion, this is the first presentation and numerical simulation study of applying pairs of parallel slot-drilled fractures to enhance the recovery from challenging unconventional reservoirs (such as the Bakken shale) that have not been successfully enhanced using the CGEOR method. The dramatic increase in recovery from SDEOR, coupled with its applicability regardless of the stress state or formation brittleness, could change how unconventional reservoirs are completed and produced in the future.

Analytical water saturation model using capacitance-resistance simulation: Clean and shaly formations

The strategies of reservoir development plans are constructed based on the economic values of reservoirs original hydrocarbon in place, which is always affected by the uncertainty in estimating water saturation. Maximum precision in water saturation is needed for reserve calculations or for decisions on whether to complete wells drilled in offshore or in unconventional hydrocarbon resources. Therefore, the development of a suitable model based on fundamental physics is sorely needed to cope with the demands of the present and future evaluation of petroleum reserves and also to overcome the shortages of current empirical models. In this study, an analytical model for the estimation of water saturation using traditional resistivity logs has been developed using capacitance-resistance modeling (CRM). This philosophy simulates the physics of saturated rock behavior to electric current by a resistor connected to a capacitor, which gives the overall electric system behavior. This system has a first order differential mathematical law. The advantage of analytical model is that it has no adjustable parameters, such as those exist in Archie's and other shaly empirical or electrochemical models. Moreover, it works in both clean and shaly formations of any kind of shale deposition within the rock matrix, which are usually determined from core analysis and laboratory experiments that consume time and cost. The mathematical derivation allows using the model for any values of porosity, shale volume, shale resistivity and true formation resistivity. Therefore, the model provides very significant outcomes of water saturation compared to Archie's and shaly empirical models. Model's reliability has been verified using laboratory measurements covering very wide range of shale content “0–0.8”, shale resistivity “0.1–48 Ω m”, formation water resistivity “0.02–10 Ω m” and formation porosity “0.015–0.48“.

Performance of the injection of different gases for enhanced oil recovery in a compositionally grading oil reservoir

Reservoir fluid characterization is one of the most important steps in hydrocarbon reservoir engineering calculations and studies. The reservoir fluid composition is not constant along the entire hydrocarbon column and varies along the vertical and horizontal directions. In most cases, such variations have been observed along the vertical direction. This is known as compositional grading phenomenon and has a strong impact on the calculation of original hydrocarbon in place, reservoir development, and oil recovery factor. In this paper, a simulation study was carried out to investigate the effects of compositional grading on reservoir fluid properties and the injection of various gases such as carbon dioxide (CO2), nitrogen (N2), associated petroleum gas (APG), N2–CO2 mixture, and water-alternating-CO2 injection into different depths of a conventional black oil reservoir in the southwest of Iran in order to detect the best injection depth and achieve the highest oil recovery factor. Due to increase in minimum miscibility pressure (MMP) with depth in compositionally grading reservoirs, MMP variations with depth is one of the main challenges in determining the optimal gas injection depth in such reservoirs. The results showed that N2, APG and N2–CO2 mixture were immiscibly injected into all depths of the reservoir due to their high miscibility pressures. The occurrence of gas override and channelling phenomena during the course of immiscible gas injection significantly reduced oil displacement efficiency. On the other hand, CO2 was miscibly injected to all reservoir layers and revealed a higher efficiency in comparison with the injection of N2, APG and N2–CO2 mixture. In fact, better miscibility development was observed in upper reservoir parts, as compared to the lower parts. Through completing injection wells at upper reservoir parts and then injecting gas into these parts, one can thus further enhance oil recovery and extend production plateau. Moreover, the results confirmed that water-alternating-CO2 injection into all reservoir depths, compared to other gas injection scenarios, was associated with increased macroscopic sweep efficiency as well as enhanced oil recovery factor.

A Structured Mobility-Based Methodology for Quantification of Net-Pay Cutoff in Petroleum Reservoirs

Summary Petrophysical cutoffs of a hydrocarbon reservoir are among the key parameters to determine net pay, net-to-gross ratio (NTG), original hydrocarbon(s) in place (OHIP), and reserves estimation. Although the concept of cutoffs has been continuously used since the 1950s, so far there is no universal agreement on their definition and quantification methods. In the most commonly used procedure, log-derived shale-volume faction (Vsh), porosity (ϕ), and water saturation (Sw) are tied back to experimentally measured rock permeability (k) values through a porosity/permeability crossplot. Then, limiting values of the three log-derived parameters are determined by use of fixed-permeability-cutoff values of 1 and 0.1 md for oil and gas reservoirs, respectively. Although these values, which are usually referred to as rule-of-thumb cutoffs, seem to be appropriate in some reservoirs, they can be misleading in most cases (e.g., tight gas and heavy oil). Furthermore, these fixed values have no mathematical basis because they were founded mainly on the basis of the experience in a number of typical reservoirs. Therefore, application of the rule-of-thumb cutoffs may cause significant errors in evaluation of petroleum reservoirs. This study focuses on technical and economic factors that have to be considered for delineating net pay. Mobility cutoff in this paper is founded on the flow equation (Darcy's law) and combined with economic-profitability condition to quantify the cutoff individually in gas and oil reservoirs. Thereafter, a novel structured procedure is provided to integrate all core, petrophysical, and fluid data with the calculated mobility cutoff, thereby introducing a single permeability cutoff for the reservoir. One of the advantages of the new procedure over the traditional methodologies is that once a cutoff is determined for permeability, it does not require subsequent tying back to ϕ,Vsh, and Sw to quantify the extra discrete cutoffs. In addition, the technique benefits from the use of permeability distribution within the reservoir in cutoff quantification. The procedure is simple, straightforward, general, and practically rationalized. Despite the previous works, it is noteworthy to mention that the newly developed approach is applicable to all types of hydrocarbon reservoirs, including typical reservoirs, tight oil and gas reservoirs, heavy-oil reservoirs, laminated-thin-bed reservoirs, and discrete stacked reservoirs, with wide ranges of rock and fluid properties. An example calculation is presented for application of the methodology in an Iranian carbonate reservoir. The example clearly illustrates how all available data from a reservoir should be integrated for appropriate determination of the permeability cutoff.

From core analysis to log-based pay identification in the Delaware Basin Wolfcamp Formation

Pay in tight-rock reservoirs is often associated with organic richness. The assumption is that the low permeabilities of the source rock do not allow for the migration of the hydrocarbon generated during the thermal maturation process. If core data are available, the water saturation, porosity, and total organic carbon (TOC) measurements can be used to confirm that the resource in place is correlated with the organic matter, which impacts the log characterization of pay. We studied the Wolfcamp A, Wolfcamp C, and Wolfcamp D tight-rock reservoirs using seven wells with core data through the Delaware Basin Wolfcamp Formation and discussed appropriate log-based pay identification methods. The linear relationship between TOC and original hydrocarbon in place (OHIP) for samples in the Wolfcamp C and D intervals validated the hypothesis of a self-sourced reservoir. We adopted the well-established correlation between TOC and formation bulk density to identify the better part of the Wolfcamp C and D reservoirs. Our core data suggested to use a bulk density of [Formula: see text] or less to define pay. The lack of trend in the scatterplot of TOC and OHIP for samples in the Wolfcamp A interval indicated that the hydrocarbon had probably migrated, at least on a local scale. In this case, pay could not be identified by log techniques developed to calculate TOC in organic-rich rocks. Instead, we built an OHIP model based on a quad combo logging suite using an ensemble learning method. This model favorably compared with a TOC-based pay flag against production logging data from two vertical producers with stages through the Wolfcamp A interval.

Influence of variograms in 3D reservoir-modeling outcomes: An example

Three-dimensional reservoir models are used routinely for various purposes in the E&P business to support value-based decisions. One of the key challenges in 3D reservoir modeling is distributing the identified facies and their associated properties in the defined 3D structural/stratigraphic framework respecting geologic knowledge and available well data. Different geostatistical techniques are used for populating the reservoir facies and properties in the 3D reservoir models which have different working inputs and assumptions. Most reservoir-characterization studies use variogram-based geostatistical-modeling methods to accurately and efficiently represent reservoir heterogeneities. The variogram-based techniques constrain 3D reservoir models to local data which represent the geologic knowledge and help to create appropriate flow behaviors through dynamic simulation. However, simulation results obtained from those techniques are highly dependent on available data, selected variogram model, and the geomodeler's geostatistical knowledge and geologic experience. To illustrate the impact of variogram modeling on 3D reservoir-modeling outcomes, multiple 3D reservoir models were generated using different variograms for a siliciclastic reservoir. As expected, the results obtained from the models show significant variations, which indicate that selection of appropriate variogram models, which is critical for facies and property distribution in 3D static models, affects original hydrocarbon in place (OHIP) and recoverable resources/reserves estimation and production forecasts. A sensitivity analysis of the variogram parameters in the 3D static models and its impact in the dynamic simulation should be considered an integral part of the 3D modeling workflow.

Analytical modeling of flow behavior in non-volumetric reservoirs

Material balance has long been used in reservoir engineering practice as a simple yet powerful tool to determine the original hydrocarbon in place. Traditional material balance methods incorporate shut-in pressure data. However, adequate shut-in pressure data is not available in some reservoirs. Integration of time variable functions and pressure transient analysis into material balance equation (MBE) provides us the flowing material balance technique. Evaluation of the initial hydrocarbon and average reservoir pressure are typical findings of such methods. Although this method is widely used in oil and gas reservoirs, it has not been implemented in water drive reservoirs so far. The objective of this study is to develop a water drive model of dynamic MBE in oil and gas reservoirs. To do so, the average reservoir pressure and water influx are calculated by a newly proposed approach which is applicable for variable rate case as well. In order to incorporate the effect of water encroachment, a novel relationship is derived for material balance pseudo-time. Even though the concept is used practically in gas reservoirs, it has not been applied in oil reservoirs yet. A numerical model was also constructed to verify the presented approach. The findings revealed that there was a high agreement between analytical and numerical schemes. • The amount of water influx can be calculated through flowing wellbore pressure. • The verification of the proposed methodology for variable rate oil and gas reservoirs was accomplished. • A new definition of pseudo-time is introduced to compensate the “non-volumetric effect”. • The proposed model is applicable to either volumetric systems or non-volumetric systems.

Impact of Uncertainty in Estimation of Shale-Gas-Reservoir and Completion Properties on EUR Forecast and Optimal Development Planning: A Marcellus Case Study

Summary The use of multistage-fractured horizontal wells has made production from shale-gas plays feasible. The production history from these wells is characterized by long linear transient flow. The key reservoir (nature) and completion (nurture) properties that affect flow behavior of the well are permeability, original hydrocarbon in place (OHIP), number of hydraulic fractures, fracture area, and fracture spacing. Understanding the interrelationship between these parameters is critical for optimal development of shale-gas-resource plays. The proposed shale-gas workflow uses a hybrid analytical model. An analytics-based diagnostic process analyzes well performance history, and a numerical model validates the feasible history-match models for representative forecasts. The model results allow the user to capture the range of uncertainty in estimating individual reservoir or completion properties, such as permeability, fracture area, and fracture spacing. The diagnostic process provides the relationship between key factors dictating well performance, such as OHIP, effective fracture area, effective reservoir permeability, effective fracture spacing, and well spacing. In this paper, wells from the Marcellus play in Pennsylvania, USA, are evaluated by use of the proposed shale-gas workflow. Surveillance is an integral part of this workflow. The paper shows how surveillance can be used for resource management and exception management. Along with data mining, the workflow accelerates the learning curve to evaluate the effectiveness of current field practices. The results help with understanding the effectiveness of proppant pumped, the potential number of contributing clusters, and production issues. Continued surveillance reduces the uncertainty surrounding all parameters. This knowledge base can then be used to optimize the asset-development strategy, maximizing the return on investment.

ProbGRV: a workflow for geostatistical depth conversion and probabilistic assessment of gross rock volume

Understanding and estimating the probability of geological success (Pg) and original hydrocarbon-in-place (OHIP) are an integral part of the geoscientist’s role from exploration though to development. This paper presents a workflow developed at Santos for the systematic assessment of two key elements in this process: the probability of structural closure (Pcl); and, the estimation of the uncertainty of gross rock volume (GRV). There are two distinct parts to the workflow. Firstly, Kriging and sequential Gaussian simulation (SGS) are used in map-based, seismic time-to-depth conversion to generate multiple equi-probable depth maps (in the order of 1,000+ realisations). Numerous depth conversion methods are considered where appropriate. Secondly, every depth map realisation is validated for structural closure around a target location (e.g. a proposed or existing well). Primary outputs from the workflow include estimates of Pcl, and probability distributions of GRV and pool area for valid maps, which may then be used directly in estimating geological risk and OHIP. Secondary outputs from the workflow include basic statistics associated with depth conversion uncertainty, such as target depth prognosis and the distribution of the depth to lowest closing contour. The ultimate objective is to provide the interpreter with a greater appreciation of the range of possible outcomes given the uncertainty in structural geometry. This workflow, named probGRV, has been designed and developed within Santos using commercially available geophysical software and in-house proprietary software. During the past few years, the workflow has been implemented on key assets at various stages of the prospect/field life cycle and in both pre- and post-drilling campaigns for audit purposes. Case studies from the Cook Field in the onshore Eromanga Basin and the Finucane South Field in the offshore Carnarvon Basin are shown to illustrate the methods and results.

Fluid- and Rock-Property Effects on Reserves Estimation

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 148717, ’Effects of Fluid and Rock Properties on Reserves Estimation,’ by Kegang Ling, SPE, Zheng Shen, SPE, Texas A&M University, prepared for the 2011 SPE Eastern Regional Meeting, Columbus, Ohio, 17-19 August. The paper has not been peer reviewed. Precise reserves calculation is fundamental for production forecasting. Great efforts are made to obtain fluid and rock properties such as porosity, permeability, saturation, rock and fluid compressibility, viscosity, fluid gravity, gas z-factor, saturation pressure, reservoir pressure, and temperature. There is always uncertainty regarding the information because of instrument sensitivity and limitations, measurement error, environmental effects, sample interval, location, and how representative of the rock the sample is. A systematic study on the effects of fluid and rock properties on reserves estimation was conducted. Introduction Fluid and rock properties control the volume of original hydrocarbon in place and the recoverable oil and gas. Uncertainty and error exist because of the instrument sensitivity and limitations, measurement error, environmental effects, sample interval, location, and how representative of the rock the sample is. Measuring rock properties under reservoir conditions is very difficult. A synthetic field was built to study the effects of fluid and rock properties. It is an oil field with aquifer support. The initial reservoir pressure is above the bubblepoint pressure. Initially, five producers were drilled to produce oil. With time, reservoir pressure declined. As the reservoir pressure declined below the bubblepoint with production, solution gas was released from oil. When the gas saturation reached critical saturation, it began to flow with the oil and water. This three-phase flow in the reservoir represents the middle and late production periods. Model Description The simulation model divides the reservoir into 93×93×2 gridblocks. The reservoir is modified to an irregular shape by assigning zero porosity and permeability to gridblocks at the reservoir edge. To populate the rock properties, different porosities, permeabilities, depths, and pay thicknesses were assigned to each gridblock. Initially, a uniform oil/water contact divided the porous sand into oil and water zones. Pressure at datum was assigned such that pressure above and below the datum can be calculated according to in-situ fluid density. Initial water saturation was assigned to respect the real oil reservoir. Rock and water compressibilities were incorporated and were assumed to be constant at different pressures. Oil viscosity varied with the pressure because solution gas has a significant effect on it. Water viscosity was kept constant. Oil gravity, gas specific gravity, water specific gravity, formation-volume factor (FVF) for oil and gas, and solution-gas/oil ratio were assigned with values often found in real oil fields.

A Bayesian Integration of Volumetric and Material Balance Analyses to Quantify Uncertainty in Original Hydrocarbons in Place

The authors use a Bayesian formulation to integrate volumetric and material balance analyses. Specifically, they apply Bayes's rule to the Havlena and Odeh material balance equation to estimate original oil in place, N, and relative gas-cap size, m, for a gas-cap drive oil reservoir. The authors consider uncertainty and correlation in the volumetric estimates of N and m, as well as uncertainty in the pressure data. They then quantify uncertainty in the estimates of N and m resulting from the combined volumetric and material balance analyses. By combining the analyses, each reduces the uncertainty of the other, resulting in more accurate in-place estimates than from the separate analyses.

Lessons Learned From Energy Models: Iraq's South Rumaila Case Study

Summary Understanding reservoir behavior is the key to reservoir management. This study shows how energy modeling with rapid material-balance techniques, followed by numerical simulations with streamlines and finite-difference methods, aided understanding of reservoir-flow behavior. South Rumaila's long and elongated Zubair reservoir experiences uneven aquifer support from the western and eastern flanks. This uneven pressure support prompted injection in the weaker eastern flank to boost reservoir energy. We learned that aquifer influx provided nearly 95% of the reservoir's energy in its 50-year producing life, with water injection contributing less than 5% of the total energy supply. The west-to-east aquifer energy support is approximately 29:1, indicating the dominance of aquifer support in the west. Streamline simulations with a 663,000-cell model corroborated many of the findings learned during the material-balance phase of this study. Cursory adjustments to aquifer properties led to acceptable match with pulse-neutron capture or PNC-derived-time-lapse oil/water contact (OWC) surfaces. This global-matching approach speeded up the history-matching exercise in that performance of most wells was reproduced, without resorting to local adjustments of the cell properties. The history-matched model showed that the top layers contained the attic oil owing to lack of perforations. Lessons learned from this study include the idea that the material-balance work should precede any numerical flow-simulation study because it provides invaluable insights into reservoir-drive mechanisms and integrity of various input data, besides giving a rapid assessment of the reservoir's flow behavior. Credible material-balance work leaves very little room for adjustment of original hydrocarbons in place, which constitutes an excellent starting point for numerical models.

Combined simulation and inversion of SP and resistivity logs for the estimation of connate-water resistivity and Archie’s cementation exponent

Knowledge of initial water saturation is necessary to estimate original hydrocarbon in place. A reliable assessment of this petrophysical property is possible when rock-core measurements of Archie’s parameters, such as saturation exponent [Formula: see text] and cementation exponent [Formula: see text], are available. In addition, chemical analysis of formation water is necessary to measure connate-water resistivity [Formula: see text]. Such measurements are seldom available in most applications; if they are available, their reliability may be questionable. We describe a new inversion method to estimate [Formula: see text] and Archie’s cementation exponent from the combined use of borehole spontaneous-potential (SP) and raw array-induction resistivity measurements acquired in water-bearing depth intervals. Combined inversion of resistivity and SP measurements is performed assuming a piston-like invasion profile. In so doing, the reservoiris divided into petrophysical layers to account for vertical heterogeneities. Inversion products are values of invaded and virgin formation resistivity, radius of invasion, and static spontaneous potential (SSP). Connate-water resistivity is calculated by assuming membrane and diffusion potentials as the main contributors to the SSP. Archie’s or dual-water equations enable the estimation of [Formula: see text]. The new combined estimation method has been successfully applied to a data set acquired in a clastic formation. Data were acquired in a high permeability and moderately high-salt-concentration reservoir. Values of [Formula: see text] and [Formula: see text] yielded by the inversion are consistent with those obtained with a traditional interpretation method, thereby confirming the reliability of the estimation. The method is an efficient, rigorous alternative to conventional interpretation techniques for performing petrophysical analysis of exploratory and appraisal wells wherein rock-core measurements may not be available.

Can We Sample the Complete Geological Uncertainty Space in Reservoir-Modeling Uncertainty Estimates?

Summary The method by which the space of uncertainty should be sampled in reservoir models is an essential point of discussion that can have a major impact on the appraisal, development and economics of hydrocarbon fields. Usually, uncertainty is assessed by way of many realizations of a given stochastic model with fixed parameters but this does not adequately sample the complete geological uncertainty space and it underestimates the uncertainty. To improve the uncertainty assessment, in this article we propose a classification and hierarchy of the sources of internal reservoir architecture uncertainty. The impact of the different levels and sources of uncertainty on elements such as original hydrocarbons in place or final recovery is quantified. In this article we demonstrate that decisions as significant as stationarity, organization of reservoir heterogeneity, choice of the global statistics and variogramme range are of prime importance in relation to the other parameters. Furthermore, we also prove that the relative importance of any parameter in assessing the uncertainty depends on the type of result—volumetric or dynamic—on which the uncertainty calculation is computed. Uncertainty of the global mean provided by hard data is assessed using sampling techniques. The coefficients of variation obtained from many field cases allow a comparison between the different distributions. It lends support to the hierarchy of the sources of geological uncertainty into six levels. The evolution of this uncertainty with the quantity of hard data, wells, and the quality of knowledge, zoning, has been quantified using synthetic models and a field case. Both a general function for the decrease of uncertainty with the quantity of the data, and a possible increase—for some parameters—of uncertainty estimates with knowledge development are demonstrated herein.

The Bahar oil and gas-condensate field in the South Caspian Basin

The Bahar Field was discovered in 1968 and contains oil and gas-condensate in sandstones and sandy siltstones belonging to the middle Pliocene Productive Series. This has a total thickness of 3600 m. It consists of alternating sandstones, sandy siltstones and shales, with thicknesses between 5 m and 50 m and is of deltaic origin. The reservoir rocks have porosities of 13-18% and permeabilities of 45-250 mD. Biomarker geochemical analyses of onshore and offshore fields show that the Pliocene oil and gas fields in the South Caspian Basin have been charged primarily from epigenetic hydrocarbons. The hydrocarbons have migrated vertically along faults from older source rocks, probably including organic-rich shales of Oligocene to early Miocene age. The Bahar Field is quite mature. Of the original hydrocarbons in place, 72% of the gas has been produced, 39% of the condensate and 11% of the oil. The main oil-bearing horizons, the Pereriv Suite (SP) and Balakhany X, are developed with reservoir pressure maintenance by longitudinal and marginal (up-dip) flooding of surfactant-added sea water.

Reserve Growth in a Mixed Sequence of Deltaic and Barrier Island Frio Sandstones: Umbrella Point Field, Chambers County, Texas : ABSTRACT

ABSTRACT Umbrella Point field exemplifies bypassed hydrocarbon potential in a mature Middle Frio Sandstone play in the nearshore Texas Gulf Coast. Located in Chambers County near the northern shore of Trinity Bay, the field has yielded 17 million barrels of oil and 100 billion cubic feet of gas from 18 stacked Frio sandstones since discovery in 1957. Most of the 36 wells were abandoned in the 1970's, and little has been done to optimize drainage patterns, to control the encroachment of water, or to prevent gas-cap expansion. Stratigraphic analysis and geological mapping, combined with analysis of individual well-production histories, were used to locate underexploited areas within these reservoirs. Two modern log suites and limited core data were used to define criteria for estimating original hydrocarbons in place and drainage areas. The Middle Frio in the area consists of stacked distributary-channel, delta-front, shoreface, and shore-parallel bar sandstones interbedded with shales. Hydrocarbons are trapped in a rollover anticline in the footwall of a growth fault underlain by diapiric shale. Original hydrocarbons in place at Umbrella Point were calculated volumetrically at 60 million barrels of oil and 300 billion cubic feet of gas. Remaining recoverable hydrocarbon potential is estimated at 32 million barrels of oil and 173 billion cubic feet of gas. Average recovery efficiency is 28.2 percent for oil and 33.5 percent for gas. The best recoveries have been from the zones characterized by uniform sandstone deposits that were redistributed during small-scale transgressions between depositional cycles.

Improved Material-Balance Regression Analysis for Waterdrive Oil and Gas Reservoirs

Summary An improved material-balance formulation is presented for determining original hydrocarbons-in-place (OHIP) in waterdrive oil and gas reservoirs. The improved formulation reduces the number of unknowns in the regression analysis through the definition of a combined aquifer/reservoir expansion term (CARET). Field examples analyzed with the CARET formulation are presented illustrating the nonunique nature of waterdrive material-balance solutions for OHIP. A method is presented for reality checking the best-fit aquifer parameters obtained from the regression analysis. The CARET material-balance formulation is shown to provide several advantages over existing regression analysis techniques.

LABORATORY TESTING FOR RESERVOIR ENGINEERS AND GEOLOGISTS—BE A DRIVER, NOT A PASSENGER!

A detailed review by Santos of all its laboratory activities has revealed that nearly all laboratory work must be very closely tailored to the needs of the reservoir in question in order to produce meaningful results. The practice of just ticking a few items from the laboratory catalogue as if one were ordering breakfast in a hotel is fatal. Instead intensive preparation of procedures is required—this may involve months of discussion with the laboratory, development of new procedures tuned to the particular reservoir, testing of these procedures and modification, etc. Often the preparation for the laboratory work will begin long before the rock or liquid samples arrive at the laboratory.Nearly all of Santos' Eromanga Basin oil reservoirs are thin (typically 30 to 40 ft gross column), have no gascap, and lie in the transition region of the capillary pressure curves. However the cores were traditionally analysed by the laboratories assuming the reservoirs extended far beyond the transition zone. This led to major inconsistencies in the results, and difficulties in comparing core results to log analysis. Procedures were developed appropriate to transitional reservoirs. Experiments were run with the new procedures. These experiments have revealed many of the hitherto unappreciated properties of transitional reservoirs, leading to a better understanding of end point saturations, log analysis, reservoir seals and how to treat reservoirs which have leaked. Low invasion coring appears to be particularly well suited to transitional reservoirs.The new laboratory procedures imply that most of our oil reservoirs are being very well swept, at least on a microscopic scale. This may have significant implications for EOR.After realising the effort that is required to keep core analysis on track Santos then extended this thinking to all laboratory work. This has led to improvements in our ability to analyse oils, waters, muds, clays and in our ability to conduct 'multi-disciplinary experiments', i.e. experiments extending across more than one laboratory. At the end of the day we are achieving better log analysis, better estimates of original hydrocarbons in place and better estimates of oil remaining after primary production.

A Volumetric-Balance Applicable to the Spectrum of Reservoir Oils From Black Oils Through High Volatile Oils

Abstract The proposed equations are consistent with the law of conservation of matter, and represent a volumetric balance on a reservoir oil bubble-point basis. Mathematically, the equations permit the incorporation of flash-liberation characteristics on all produced fluids and differential-liberation characteristics on remaining reservoir fluids. Although flash - liberation and differential - liberation characteristics are formally stated, deviation from these liberation procedures (such as constant-volume technique in lieu of differential technique) can be incorporated in the equations. The proposed equations permit definition of natural depletion performance for closed reservoirs and are applicable to open reservoirs, i.e., those connected with aquifers. Original volume of bubble-point oil (oil-hydrocarbon pore volume) as well as relative permeability ratios (kg/ko) and reservoir oil and gas saturations can be defined from past reservoir pressure-production information. Laboratory-determined PVT characteristics, along with corresponding solution-gas content and viscosity, all vs pressure are necessary for the use of the equations. The equations are suitable for desk-type calculators or electronic computers. Consistent with other volumetric material-balance procedures, they are solved by trial methods. Introduction All material-balance principles are based upon the theory of the law of conservation of matter; i.e., in a hydrocarbon system such as a productive reservoir, all hydrocarbons must be accounted for at all times. This may be stated very simply as follows. (Original Hydrocarbons) = (Remaining Hydrocarbons)+ (Produced Hydrocarbons)...................(1) This basic equation may be solved on a weight basis (molal-balance) or on a volume basis (volumetric-balance), or a combination of the two. The volumetric-balance approach permits the basic Eq. 1 to be written on a constant reservoir volume basis, as follows. (Reservoir Volume of Original Hydrocarbons) =(Reservoir Volume of Remaining Hydrocarbons)....(2) When the reservoir is geologically open (i.e., the hydrocarbon accumulation is in communication with an aquifer), then provision for water encroachment will modify Eq. 2 for the following volumetric balance. (Reservoir Volume of Original Hydrocarbons) =(Reservoir Volume of Remaining Hydrocarbons) +(Reservoir Volume of Net Water Encroachment)....(3) The application of these basic equations, of course, is dependent upon the conversion of reservoir fluids between reservoir and surface conditions consistent with the original intent of the equations as previously published. No particular problems are encountered in applying the volumetric-balance equations when the flash-liberation and differential-liberation fluid behaviors are the same; some reservoir oils closely approach these conditions and generally are referred to as "black oils". In contrast, the use of such equations in the volatile-oil range, without proper conversion of surface produced volumes of gas and liquids back to definitive reservoir production, will lead to non-representative reservoir performance calculations. The problem, therefore, is how to calculate representative reservoir performance when there is a difference between flash-liberation and differential-liberation fluid behavior. One approach presented in several published papers incorporates the molal-balance Eq. 1 together with the volumetric-balance Eq. 2 as follows. Molal Balance (Original Hydrocarbons in Place) - (Produced Hydrocarbons)= (Remaining Hydrocarbons) ......................(4) Volumetric Balance (Reservoir Volume of Remaining Hydrocarbons) =(Reservoir Volume of Original Hydrocarbons)......(5) Thus this method incorporates Eqs. 4 and 5 as a combination molal-balance and volumetric-balance technique. The method is recognized as fundamental; however, definitions of hydrocarbon densities as well as equilibrium ratio (K = y/x) at elevated pressures and temperatures are subject to extensive laboratory testing. JPT P. 589^

Material Balance Calculations with Water Influx in the Presence of Uncertainty in Pressures

Abstract This paper presents a technique for calculating the original amount of hydrocarbon in place in a petroleum reservoir, and for determining the constants characterizing the aquifer performance, based on pressure-production data. A method for doing this based on a least-squares line-fitting computation was proposed by van Everdingen, Timmerman and McMahon in 1953. We found that their method would not work when there is error in the reservoir pressure dataeven moderate error. The technique presented here appears to give reasonable answers when pressure data are uncertain to the degree expected in reservoir pressure determinations. The major change introduced in the present analysis is to limit the least-squares line-fitting to yield only one constant the amount of hydrocarbon in place. The water-influx constant is then taken as proportional to the oil (or gas) in place. The constant of proportionality can be computed from estimates of effective compressibility and reservoir water saturation. It is also pointed out that the commonly used least-squares analysis assumes all of the uncertainty to be in the dependent variable. The material balance should be arranged so that this condition is fulfilled if correct inferences are to be made from statistical calculations. Examples are shown of the application of the new technique to gas reservoirs both hypothetical and real and to the oil reservoir example of van Everdingen, Timmerman and McMahon. Introduction The amount of hydrocarbon originally in place in a petroleum reservoir can be estimated by means of the material-balance calculation. Simultaneous observations of pressure and amounts of produced fluids are required, together with the PVT data applicable to the reservoir fluids. If water encroachment is occurring, it is desirable to try to infer the behavior of the aquifer, as well as the original hydrocarbon in place, from the pressure-production data. This imposes additional demands on the method of calculation, and uncertainty in the data can result in large uncertainty in the answer. In addition, if the size of a gas cap is to be established, the whole problem becomes indeterminate, as pointed out by Woods and Muskat. Brownscombe and Collins simulated a gas reservoir and its aquifer on a reservoir analyzer and derived quantitative information on the effect of uncertainty in pressure and aquifer permeability on computed gas in place. Among the various techniques of estimating the performance of an aquifer, the method of van Everdingen and Hurst, based on compressible flow theory, seems to have been the most generally successful (see Ref. 4, for example). In this paper we shall confine ourselves to their representation of the aquifer. In 1953, van Everdingen, Timmerman and McMahon introduced a statistical technique for deriving the amount of oil originally in place and the parameters which describe the aquifer. (We shall refer to this technique as the "VTM method", as suggested by Mueller.) Their example reservoir had no gas cap. It has been our experience that the VTM method gives a reasonable answer when the data are very accurate, but that inaccuracy (particularly in pressure) can cause the method to break down. The effect was first observed in gas reservoirs, but has since been seen in oil reservoirs also. In this paper we present another statistical method which has been successful in achieving a reasonable answer where the VTM method has failed. In the new method, one less parameter is derived from material-balance computations. It is assumed that values can be established for effective compressibility in the aquifer and reservoir water saturation independently of the material-balance calculation. The water-influx constant can then be obtained from these data and the quantity hydrocarbon in place. SPEJ P. 120^