Amount Of Oil In Place Research Articles

Performance of CO2 Foam Huff and Puff in Tight Oil Reservoirs

The challenges associated with unconventional reservoirs are related to their intrinsic nature: extremely low porosity and permeability. Combinations of horizontal wells and multistage hydraulic fracturing techniques have been developed to overcome the production obstacles and unlock the vast amount of oil in place in such formations. However, oil production still exhibits a sharp decline within the first 2 years after the stimulation, leading to an oil recovery of less than 15%. Thus, enhanced oil recovery methods need to be investigated to further increase the production rates and the recovery. In this study, laboratory experiments and numerical simulations were conducted to evaluate the performance of the CO2 foam huff and puff process and its impacts on oil recovery in tight oil formations. More specifically, the foam half-life was measured as a function of surfactant concentration and followed by the foam drainage ratio and its rheological properties in the subsequent tests. Reservoir simulations were conducted using the lab data and the field data collected from Cardium formation. Sensitivity analyses were finally carried out to investigate the effects of controlling variables on the CO2 foam performance. Experimental results revealed that the optimal surfactant concentration was found to be 0.2%, which is the critical micelle concentration point. Simulation results show that CO2 foam huff and puff can increase the oil recovery by more than 11% compared to that of the primary production. Moreover, sensitivity analyses show that the production time, injection time, and soaking time are the main effecting parameters, while the injection rate and the incremental injection rate are less important.

STATIC MODELING OF THE RESERVOIR FOR ESTIMATE OIL IN PLACE USING THE GEOSTATISTICAL METHOD

Three-dimensional simulation using geostatistical methods in terms of the possibility of creating multiple realizations of the reservoir, in which heterogeneities and range of variables changes are well represented, is one of the most efficient methods to describe the reservoir and to prepare a 3D model of it and the results have been used as acceptable results in the calculations due to the high accuracy and the lack of smoothing effect in small changes compared to the results of Kriging estimation. The initial volumetric tests of the Hendijan reservoir in southern Iran were carried out according to the construction model and the petrophysical model prepared by the software and according to the fluid contact levels, and the ratio of net thickness to total thickness in different reservoir zones. The calculations can be distinguished based on the zoning of the reservoir and also on the basis of type of facies. Accordingly, the average volume of fluid in place of the field is calculated in different horizons. The results of the simulation showed that the Ghar reservoir rock has gas and Sarvak Reservoir has the largest amount of oil in place.

Investigation of hydraulic fracturing operation and fracture propagation simulation in reservoir rock

For many decades most oil wells in Iran have produced using their natural flow potential and haven’t needed to be fractured. As time goes by, the reservoir pressure depletes and the need for hydraulic fracturing as a stimulation practice arises. Nonetheless there is no record of successful hydraulic fracturing in Iran.The Bangestan reservoir with a suitable amount of oil in place and good rock reservoirs, has been selected for the present research work. In this work, the in situ stress profile was calculated by using the available petrophysical data. This is achieved by using poroelastic theory for the stresses, and the Mohr–Coulomb criterion to predict failure. The model leads to easily computed expressions for calculating the pressure required to maintain hydraulic fracturing. Then the appropriate depth for treatment was determined. The results indicate that Ilam and Sarvak formations could be good candidates for hydraulic fracturing. Then, for two layers, a hydraulic fracture was designed and the production was predicted and the Net Present Value (NPV) resulting from the fracture of both layers was investigated.

Effect of pressure gradient on the flow of oil and water in gel-filled pore

Water is injected into oil-bearing porous rock for displacement of oil. Water tends to flow through high permeablity streaks, leaving significant amount of oil in place, unless the streaks are plugged by structure-forming fluids such as, polymer–gels. Cr(III)–polyacrylamide gel finds an use even in production well, as this gel structure offers easy flow of oil, apart from restricting water flow. The resistances that water and oil encounter, while flowing through the gel structure are characterized in this paper. The permeability of Cr(III)–polyacrylamide gel, held in tubes was evaluated as function of oil and water flow rates. This was observed that immediately after the rupture, a new pore space was created by the injected fluid. Same pathways were used by the other phase, i.e., water or oil, injected subsequently. The volume of the pathway within the gel structure was also monitored during the flow experiments. After complete recovery of the new pore space, the permeability was found to increase at higher flow rates. The change in permeability was completely reversible, and a cycle of step-wise ascent and descent in flow rates did not show any significant hysteresis. A theoretical model is developed that accounts for the rupture in the gel, and the deformation of the fracture inside the gel due to imposed pressure gradient. The model explains the power-law relationship between permeability and flow rate, as observed in experiments. The model identifies a ratio of interfacial to elastic deformation, in terms of a dimensionless parameter, σ/( GL). This ratio controls the relative reduction in water permeability with respect to the reduction in oil permeability. Experiments were conducted in Berea sandstone rock, and similar trends, as described above were observed.

Hydraulic Fracturing With Heated Fluids Brings Success in High-Pour-Point Waxy-Oil Reservoir in India

Summary Most existing production of waxy oils occurs in high-permeability formations, and wax issues are mostly a problem in the production tubing or pipeline. Large reserves also exist in low-permeability formations that require hydraulic fracturing for economic production. Such a reservoir was recently discovered in Rajasthan, northwest India, overlying a more typical high-permeability formation, both with high-pour-point waxy oil. Because a very large amount of oil in place is present in the low-permeability formation, two fracturing campaigns were performed in two different horizons to assess the potential for successful well stimulation. The first fracturing campaign (on four wells) showed limited success. A study was performed to determine the reason for the failure, and significant changes were made for the second campaign. This paper documents the second campaign. This campaign featured the first successful use in India of heated fluids to stimulate a shallow, low-permeability, massive oil reservoir containing high-pour-point waxy oil.

Spatial 87Sr/ 86Sr variations in formation water and calcite from the Ekofisk chalk oil field: implications for reservoir connectivity and fluid composition

The 87Sr/ 86Sr ratios of formation waters from the chalk of the Ekofisk oilfield were measured using a new technique: extracting salt residues from the interstices of core samples. In the Danian Ekofisk Formation, the chalk matrix itself has 87Sr/ 86Sr and δ 13C values characteristic of Danian seawater, even though δ 18O data indicate the presence of varying quantities of diagenetic carbonate cement. In the Ekofisk Formation, porewater 87Sr/ 86Sr values are very constant (range: 0.70786-0.70810). The formation water probably contains locally derived Sr from carbonate, plus a small contribution from noncarbonate minerals with higher 87Sr/ 86Sr. In the underlying Tor Formation, chalk samples containing a mixture of primary chalk and later cement, have 87Sr/ 86Sr values that rise with depth to a maximum of 0.70865, much higher than contemporaneous seawater. Porewater 87Sr/ 86Sr values increase even more dramatically with depth to a maximum of 0.70988. Both cement and waters have been influenced by Sr with a high 87Sr/ 86Sr probably derived from underlying sedimentary rocks. Comparison with waters brought to the surface together with produced oil indicates that the depthwise increase in 87Sr/ 86Sr reflects an increase in salinity from ∼50,000to∼140,000 mg/l total solute content. This suggests that Zechstein evaporites may be the source of the radiogenic Sr in the Tor Formation. The difference in isotope composition between carbonates and waters in the Ekofisk and Tor Formations indicates that their hydrochemical systems have evolved differently during diagenesis. This is due to the barrier effect of the Ekofisk Tight Zone, a hardground at the base of the Ekofisk Formation which effectively splits the reservoir vertically into two. This study thus provides a new way of determining the positions of permeability barriers in oil reservoirs. Also demonstrated for the first time is the existence of vertical variations in salinity of water in oil. Such variations could have important implications for the calibration of resistivity logs and calculation of the amount of oil in place.

Enhanced oil recovery: Definitions, fundamentals, applications, and research frontiers

This paper describes the highlights of current oil-recovery technology, including primary, secondary, tertiary, and enhanced recovery processes. Fundamental displacement phenomena are discussed: (1) from a macro-view, such as injection- and production-well patterns, impermeable barriers, and geologic faults; and (2) from a micro-view, which considers oil displacement on a pore-by-pore basis in a three-dimensional interconnected network of flow channels. Applications used to illustrate displacement fundamentals included the major features of water, polymer, and micellar flooding; and steam and CO 2 injection. Also discussed are two principal frontiers of enhanced oil recovery research: definition of the reservoir, and independent measurement of the amount of oil in place.

A New Method for Determining a Well's In-Place Hydrocarbons From a Pressure Buildup Test

Abstract A method for estimating in-place hydrocarbons from pressure buildup tests has been derived and applied to actual well test data. Four examples utilizing this new method are presented and compared with in-place hydrocarbon estimates determined by other methods. In addition, a derivative application of the method is described for calculating stabilization tune of gas wells which have well-defined production-pressure decline curves from which reliable estimates of gas in place can be made. The method presented in this article is not based on new theory; the calculations can easily be done on a slide rule or a desk calculator, and most of the various reservoir parameters which are commonly determined from well logs or core analysis are not required. Introduction Most routine approaches for gas-in-place determinations require that years of pressure-production data be available before original pore volume estimates, based on log interpretation, can be verified. The original volumetric reserves estimates can often vary by a factor of two or more from results obtained by actual production data. Unfortunately, most significant economic decisions must be made early in the life of a well, often before reliable reserves information is available. In the case of oil wells. the original oil-in-place volume may never be verified from production decline curves unless these are supplemented with period: c bottom-hole pressure tests and material balance determinations are made. Hydrocarbon pore volume estimates require values for porosity, water saturation, drainage area and reservoir thickness. Porosity, water saturation and reservoir thickness can be obtained from well logs; however, they are normally applicable to only the vicinity adjacent to the wellbore. Generally, gas-bearing reservoirs are heterogeneous and erroneous reserve estimates may be caused by assuming various parameters constant throughout the reservoir. Gas reservoirs are normally drilled on much wider spacing than oil reservoirs and, as a result, core and well log data are assumed representative of a relatively larger area in a gas reservoir. Hydrocarbon pore volume estimates for each new well usually assume the drainage area to be equal to the well's unit acreage even if the well is far removed from the center of the unit. Pressure transients which result from drawdown, buildup, fall-off or interference tests contain much quantitative information about the well and the reservoir. Proper analysis of these tests permits the engineer to determine wellbore damage, effective capacity (kh), static reservoir pressure, distance to boundaries or flow restrictions, reservoir size and stabilization characteristics. Carefully followed well test procedures and methods of analysis can also result in reliable pore volume estimates. A method was derived by Park Jones' for determining the reservoir limits from a buildup test. By combining the reservoir limits radius with well log parameters, it is possible to determine oil or gas reserves. The new method developed in this article, and illustrated by examples from field tests, does not require various well log parameters. The gas in place determined from buildup tests agrees remarkably well with volumetric calculations based on well log and geological interpretations. The method has also been adapted for use in determining oil in place from buildup tests on oil wells. One example of this application is presented which also agrees closely with the amount of oil in place determined volumetrically by the operator of the well. The calculations can easily be made on a desk calculator and none of the various well log parameters are required. Development of Equations The most commonly used equations in unsteady-state analysis are those developed by Muskat, van Everdingen and Hurst and Horner. Many authors have investigated and accepted these equations as valid. JPT P. 859ˆ

Material-Balance Analysis of a Water-Drive Reservoir with An Unusual Development History

Abstract Frequently, the analysis of an undersaturated waterdrive reservoir by a material balance is unsatisfactory because reservoir conditions do not reasonably satisfy the assumptions of the material-balance equation. This occurred in the case of a Devonian reservoir in West Texas which proved difficult to analyze because of a rather unusual development history. The standard material-balance analysis technique had to be modified before a satisfactory oil-in-place value could be determined. The modified technique consisted of a material-balance formulation which permitted the analysis of pressure-production data from separate portions of the reservoir with one equation; it also permitted a judicious application of the "least-squares method" to reduce the effect of inherent inaccuracies in the early data. The analysis was accomplished with the aid of an IBM 704 computer and represents a good example of the flexibility in material-balance calculations that may be obtained by computer usage. Introduction The determination of oil in place and water-influx performance of undersaturated water-drive reservoirs, using the material-balance principle, is a well established practice. Frequently, however, the material-balance results are questionable, and the practicing engineer begins to regard such calculations as either totally unreliable or applicable only to a strange breed of reservoirs which apparently are owned only by competitors. Inconclusive or questionable results will occur when reservoir conditions do not reasonably satisfy the assumptions of the material-balance equation and when the true average reservoir pressure is not accurately represented by an average of individual well pressures. These difficulties often can be overcome by modifying the material-balance equation to introduce additional independent parameters which may be assigned various values during the calculations to determine the effects, within certain limits, of possible inaccuracies in basic assumptions. This is exemplified by the reservoir study which is the subject of this paper. The subject reservoir is a structural trap in the Devonian dolomite-limestone formation of West Texas. The initial reservoir pressure of 3,231 psi declined to about 2,250 psi during 12 years of production, but it has remained above the saturation pressure of 1,775 psi. Material-balance calculations, made early in the life of the field, indicated a much larger reservoir than had apparently been defined by the drilling of 10 producing wells and three dry holes. Although a material balance during the early life of an expansion-drive reservoir is notably unreliable, the effort proved rewarding in this case. The consistency of the calculated value of oil in place after nearly eight years of production prompted additional drilling which eventually extended the field to include a volume approximately three times that of the initial discovery and resulted in an additional 28 producing wells. Even with the additional drilling, the amount of reservoir pore volume was still questionable. Volumetric calculations indicated 40 million STB of oil in place, but very few wells had penetrated the full Devonian section; since the top of the Devonian is eroded over most of the structure, the estimated pay thickness may be considerably in error. Material-balance calculations, although not so consistent as the earlier ones, gave an oil-in-place value of about 140 million STB and no definite indication of water influx. Furthermore, data from drill-stem tests of the Devonian formation taken in dry holes in the vicinity of the reservoir indicated the possibility of a very limited aquifer. The pressure-decline curves indicated a recovery above saturation pressure much greater than normal for an expansion drive--if the amount of actual oil in place was reasonably close to the volumetric estimate. JPT P. 37^

Field Results of South Belridge Thermal Recovery Experiment

Published in Petroleum Transactions, AIME, Volume 213, 1958, pages 236–244. Abstract Results of a field research project on the thermal recovery of oil by movement of a combustion front are presented. This field test was conducted in the South Belridge field, Calif. The test pattern was a single 2.5-acre five-spot pattern in the 700-ft deep Tulare sand. Results of this project indicate the technical feasibility of producing high viscosity, low-gravity crude oils by thermal means. It was demonstrated that heavy oils could be moved rapidly over considerable distances by thermal drive, and that high percentage recoveries of oil could be effected. The bulk of the oil recovery came after arrival of the burning front at a production well. However, rapid corrosion and high-temperature failure of conventional pipe and equipment both below and above surface occurred. Stainless steels gave more satisfactory performance under these conditions than did conventional steels. Oxygen was seldom observed in gas from wells ahead of the burning front, and it appears that the front was continuous throughout the life of the experiment. Introduction During late 1953 and early 1954, industry-wide attention was focused on the thermal recovery of oil by movement of a combustion front through an oil zone. Two separate Oklahoma field tests were described in publications by. Kuhn and Koch, and Grant and Szasz. To obtain basic information needed for making engineering and economic appraisals of commercial recovery of heavy oil by this thermal recovery method, a new field research project was started May 31, 1955. Twelve oil companies contributed to this project with General Petroleum Corp. as operator. Since combustion recovery experiments with heavy oils in other areas had been conducted In small patterns, an important purpose of this test was to determine whether the process could be operated in a pattern of near-commercial well spacing. The South Belridge field, located 30 miles north of Taft, Calif., was chosen because its oil sands are similar to many heavy oil sands which typically have low primary recovery and leave a large amount of oil in place. Such fields are not particularly suited for common secondary recovery methods.