Steam Soak Research Articles

Determination of the main technological parameters of cyclic-steam stimulation of oil reservoirs with account of heat losses along the borehole

Due to the decline in light oil reserves, the development of high-viscosity oil fields has become more relevant today. One of the most common methods of thermal enhanced oil recovery is cyclic-steam stimulation. Compared to other techniques, this method has an advantage of providing higher thermal efficiency due to selection of its parameters with account of variations in the basic properties of a heat carrier as it moves towards the well bottom. The purpose of this work is to create a method for rapid assessment of optimal technological parameters of cyclic-steam stimulation, in which the temperature distributions along boreholes obtained from geophysical research are used as initial data. The created method allows determination of the time of hot carrier injection, steam soak and oil production. The scientific novelty of the study refers to the fact that an integrated approach relating the problem of hot carrier transportation with the problem of determination of optimal parameters for reservoir treatment is proposed for the first time. The cyclic-steam stimulation process is described by the equations of mechanics of multiphase systems. Euler’s method is used to solve the resulting system of equations. The paper presents: functions of depth-wise distributions of pressure, temperature and velocity and dryness fraction of steam; temperature distribution in the multilayer wall of the well and in the rock (considering a specified heat transfer between the layers of the well materials, water and rock at known temperatures); optimal values of the time of hot carrier injection, steam soak and oil production. The calculations have shown that, due to the in the layer of basalt fiber, the temperature in the multilayer wall of the well decreases within 80%. The maximum value of additional cumulative oil recovery has been established by analyzing the calculated bottom-hole parameters of the heat carrier.

Investigation on the Benefits of Steam Adsorption and Distribution during Cyclic Steam Injection to Improve Oil Recovery - FNE Case Study, Sudan

One of the main types of Enhanced Oil Recovery (EOR) methods is thermal stimulation method which is an increasingly common method of extracting heavy oil. there are different forms of the technology of thermal method Cyclic steam stimulation, Steam flooding and In-situ combustion “Fire flooding” are commonly applied to oil reservoirs, which are relatively shallow very viscous oil at the reservoir temperature, the most widely used steam injection methods for heavy oil recovery is Cyclic Steam Stimulation “steam soak or huff and puff” method. Most of commingle thermal wells has a problem in steam intensity distribution among the layers, which will lead to inconsistency in steam adsorption and some layers would adsorb more than double of the designed steam injected volume. This phenomenon will lead to low productivity and negatively impact the distribution of water cut in the different layers. Steam adsorption and distribution represent one of the main challenges of heavy oil production from Sudanese oil fields, very limited studies have been conducted in this field in Sudan oil fields, and this study is focused on addressing this challenge to maximize recover factor from each well and each field. In this paper the challenge facing Bentiu reservoir in Fula North East (FNE) located in heavy oil zone with target of production around 85% of the total reserves will be highlighted. The field has shallow depth ranging between 520m and 700m and low pressure gradient 1.09 psi/m, and with reservoir temperature around 44 o C. The study covers an investigation on the benefits of steam adsorption to enhance the oil recovery focusing on the distribution of the steam inside the layers, also cover the analyzing and reviewing the actual steam intensity distribution among each layer in the two wells that are later compared with the designed ones. In a later stage, we designed a pilot model that has been designed using advanced thermal EOR Simulator to understand the effect of commingle injection and production (Steam adsorption and distribution) using data from single layers. An optimum steam injection protocol that will maximize the recovery factor from these oil zones has been designed and the results show that the injection rate has significant effect in steam distribution. Keywords: Cyclic Steam Stimulation, Enhanced Oil Recovery (EOR), Steam-Assisted Gravity Drainage (SAGD), Hot water flooding and In situ combustion,

Microbial enhanced oil recovery of oil-water transitional zone in thin-shallow extra heavy oil reservoirs: A case study of Chunfeng Oilfield in western margin of Junggar Basin, NW China

Abstract To improve the production effect of oil-water transitional zone in thin-shallow extra heavy oil reservoirs of Chunfeng Oilfield in western marginal area of the Junggar Basin, microbial enhanced oil recovery was studied taking the P6-P48 well of the oil-water transitional zone as an example. In the early stage of steam stimulation, the P6-P48 well was shut-in due to high water cut caused by edge water incursion, and analysis showed that its reservoir conditions are suitable for microbial cold production technology. According to the P6-P48 well oil sample composition, the study screened indigenous microbe strain of bacillus XJ2-1, aeruginosa XJ3-1, Dietz's bacteria Z4M8-2, inoculating microbes strain of bacillus SLG5B10-17, nutrient solution, and activator; and designed microbial injection scheme according to near borehole zones treatment radius. In September 2014, 865 m 3 of microbial bacterial liquid, nutrient solution and activator was injected and the well was shut in for 166 d of reaction time. The well-hole was opened to produce in March 15, 2015, and has produced 405 d until April 30, 2016, producing oil 3 464 t. The 50 °C degassing crude oil viscosity was decreased by 58% after microbial enhanced oil recovery, and the injected live bacteria was found in produced fluid, with more quantity, indicating that the injected bacteria are adaptive and has reproduced in formation condition. Compared with 16 adjacent wells of steam soaking, microbial enhanced oil recovery has long valid period and better economic benefit. Microbial enhanced oil recovery also got good results in the P6-P49 and P6-P47 wells.

Application of Monitoring Data of Multi Point Temperature and Pressure in Regulation of SAGD Well Group

SAGD has been a major replacing technology in Liaohe Oilfield at the late stage of steam soaking and the scale is expanding gradually, How to monitor the SAGD horizontal production well effectively is the key problem in operating the SAGD well group, multi-point monitoring technology is adopted in Liaohe Oilfield to Monitor multi point temperature and pressure of production wells in the SAGD well group, Multi point measured data of temperature and pressure analysis method is obtained through typical examples analysis, and the important role of multi-point monitoring data is pointed out in regulation of SAGD well group.

Applied Research of Heat Self-Generated CO2 Technology in Steam Huff and Puff

Heat self-generated CO2 technique is proposed, which is focused on the problems of recovery difficulty, poor effect steam soaking and so on for heavy oil reservoirs. This technology is combining of steam flooding and gas flooding and so on. Its main mechanism is the application of steam heating blowing agent to generate a large volume of gases (including CO2, NH3, etc) in the formation. While some of these gases acting with the oil to reduce the oil viscosity, some form miscible flooding to reduce water interfacial tension, so as to achieve the purpose of enhancing oil recovery. An optimized selection of the heat blowing agents was performed. By comparison the difference before and after the reaction of blowing agent solution, the increase of alkaline is occurred after the reaction, and is helpful to reduce oil viscosity and lower interfacial tension, etc. Studies indicate that heat-generating CO2 flooding technology can get a maximum viscosity reduction rate of 76.7%, oil-water interfacial tension decreased by 54.77%, further improve oil recovery by 4.17% based on the steam drive, which shows a technical advantage toward conventional EOR method. The field experiments indicate that the technique can greatly improve the oil production, which will provide a powerful technical supporting for the efficient development of heavy oil.

Laboratory Study on Carbon Dioxide and Surfactant Assisted with Steam Flooding in Qi 40

The natural oil sand from Qi 40 block formation is made into 5 teams total 10 high temperature and pressure long double tube reservoir nonhomogeneity models .The experimental oil is simulation oil which is made by mixing the wellhead crude oil with diesel. On the base that steam soaking and steamdriving recovery reach to the current oilfield average level, we do 1 group double tube steam +CO2 .The natural oil sand from Qi 40 block formation is made into 5 teams total 10 high temperature and pressure long double tube reservoir nonhomogeneity models .The experimental oil is simulation oil which is made by mixing the wellhead crude oil with diesel. On the base that steam soaking and steamdriving recovery reach to the current oilfield average level, we do 1 group double tube steam +CO2 composite displacement experiment and 4 group double tube surfactant adjustable profile + steam +CO2 composite displacement experiment. And record after steamflooding steam drive with carbon dioxide and surfactant improvement value. The results show that in the steam composite flooding, enhanced oil recovery rate increases as the number of composite plug PV growing. Carbon dioxide and steam are injecter by 1:1 alternately and composite plug is 0.3PV, in which enhanced oil recovery rate can reach 19% and cost of oil displacement agent is 38.77 Yuan/ton of oil. Carbon dioxide and II thermostability discharge aiding agent are injecter by 1:1 alternately and thebest composite slug is 0.3PV, in which enhanced oil recovery rate can reach 23.7% and cost of oil displacement agent is 289.66 Yuan/ton of oil. When the plug PV number is same(0.3), surfactant + CO2 composite plug can improve more 4.7% than steam +CO2. Hence, thermostability discharge aiding agent have some effects on improving recovery.

Improved Genetic Algorithm for Injection Production Parameters Optimized Design of Steam Soak Well

He development effect of steam soak well is influenced by the combination of the following parameters: injection speed, dryness fraction of steam, cyclic steam injection volume, soaking time and bottom hole flowing pressure. Take the advantage of annealed genetic algorithm which characterize with the traits of fast search and globally optimization. Based on the mathematical model of the output of the steam soak well, and optimize injection production parameter of the steam soak well which is aimed at the cycle average daily profit maximum, and make the field application.

A Study on Effect Evaluating and Parameters Sensitivity Analyzing of Superheated Steam Soak in Heavy Oil Reservoirs

By using the technology of numerical reservoir simulation, we have compared superheated steam soak with saturated steam soak in area of heating, effect of distillation, capability of increasing oil production, volume of steam in need to evaluate the effect of superheated steam soak in heavy oil reservoirs. Analyzed the sensitivity of parameters like steam injection intensity, steam injection rate, soak time, degree of superheat to conclude the rule that they affect on recovery percentage. The research shows that, heating radius of superheated steam is greater than that of saturated steam, distillation effect of superheated steam is better than that of saturated steam, oil production of superheated steam is more than that of saturated steam, steam volume in need of superheated steam is less than that of saturated steam. Recovery percentage of superheated steam soak increases but more and more slowly with the increase in steam injection intensity, increases first and then decreases with the increase in steam injection rate, increases first and then decreases with the increase in soak time, increases but more and more slowly with the increase in degree of superheat. Influence of steam injection intensity is obvious to recovery percentage, but influence of other factors like soak time, steam injection rate, degree of superheat is insignificant.

Effects of Steam Soak on the Two Eocene Heavy Crude Oils from the Urdaneta District (Venezuela)

Simulation studies of steam-alkaline injection were made using the only two Eocene viscous crude oils from the Urdaneta District (Venezuela). Reactors were stainless steel and work conditions were a temperature of 200°C, 20 days' reaction time, and an alkali concentration of 4000 ppm. The aim of this work was to evaluate chemistry changes in the saturates and aromatics of both crudes as a result of the crude-alkaline-solid phase interactions. There were significant variations in the biomarker distribution in the two crudes (higher for the Boscán crude), particularly in the mono- and triaromatic steranes, and benzotiophenes of the two crudes.

Prospects of applying bottom-hole electrothermal complexes to increase oil recovery of layers with high-viscosity oil

The prospects of developing high-viscosity oil deposits in the Russian Federation are estimated. Based on the example of the Usinsk deposit, it is shown that using bottom-hole electrothermal complexes to increase oil recovery of layers is more appropriate than traditional methods of recovery intensification that use cyclic steam soaking.

Steam flooding after steam soak in heavy oil reservoirs through extended-reach horizontal wells

This paper presents a new development scheme of simultaneous injection and production in a single horizontal well drilled for developing small block reservoirs or offshore reservoirs. It is possible to set special packers within the long completion horizontal interval to establish an injection zone and a production zone. This method can also be used in steam flooding after steam soak through a horizontal well. Simulation results showed that it was desirable to start steam flooding after six steam soaking cycles and at this time the oil/steam ratio was 0.25 and oil recovery efficiency was 23.48%. Steam flooding performance was affected by separation interval and steam injection rate. Reservoir numerical simulation indicated that maximum oil recovery would be achieved at a separation section of 40–50 m at steam injection rate of 100–180 t/d; and the larger the steam injection rate, the greater the water cut and pressure difference between injection zone and production zone. A steam injection rate of 120 t/d was suitable for steam flooding under practical injection-production conditions. All the results could be useful for the guidance of steam flooding projects.

Steam/bacteria to treatment of asphaltene deposition in carbonate rocks

In this project, steam and bacteria were tested to stimulate the damaged limestone cores. Several dynamic experiments were conducted to determine the effect of asphaltene on the permeability of limestone cores. Plugging effects due to asphaltene deposition were evaluated through comparison with reference permeability measured prior to and after oil flow. Damaged cores were subjected to different type of treatments: a steam soak process and bacteria. The permeability of the cores was measured after each treatment. Core impairment resulting from in situ asphaltene deposition, was found to cause an 8% to 93% loss of initial oil permeability depending on rock permeability and injection rate. Core stimulation resulting from steam soak treatment, was found to cause an 18% to 400% improvement on the damaged core permeability depending on rock permeability and soaking time. Core stimulation results from bacteria treatment, was found to cause a 41% to 129% improvement on the damaged core permeability depending on core permeability and the extent of the damage.

In Situ Upgrading of Heavy Oil

Abstract Low temperature oxidation (LTO) of hydrocarbon liquids generally results in a more viscous end product; this has clearly been shown in the literature of the past 30 years. However, under the right conditions, LTO can be used to achieve viscosity reduction in heavy oils. The In Situ Combustion Group at the University of Calgary conceived of a two-stage LTO process whereby oil is contacted with air, first at low, then at elevated, temperatures. The first, low temperature, step incorporates oxygen into some of the hydrocarbons, yielding labile bonds that should break at lower-than-usual temperatures. Once these free radicals are formed, the second step promotes bond cleavage at higher temperatures, resulting in shorter chain hydrocarbons. In a field situation, this process would be analogous to first injecting air into a formation at low temperature, then starting a steam soak or steam flood. Experimental runs carried out on Athabasca bitumen examined the effects of oxygen partial pressure, temperature, reaction time, and the presence of rock and brine. On completion of each experiment, the gas composition was determined using gas chromatography, water acidity (pH) was measured, and the hydrocarbon products were analysed for coke and asphaltenes contents, viscosity, and density. Some instances of viscosity reduction have been observed; these are linked to lower oxygen partial pressures, higher second stage temperatures and longer run times. This paper discusses the experimental work, and estimates the optimum conditions for successful viscosity reduction of a given heavy oil. Introduction Heavy oil and oil sands are important hydrocarbon resources that total over 10 trillion barrels, nearly three times the conventional oil in place in the world. The oil sands of Alberta alone contain over two trillion barrels of oil. In Canada, approximately 20﹪ of oil production is from heavy oil and oil sand resources(1). The application of thermal energy to increase heavy oil recovery has become more popular as conventional reserves decline. Steam injection accounts for the majority of the thermal recovery projects currently in operation; however in situ combustion offers many theoretical advantages if the operational characteristics of the process are incorporated in the design and operation of the field project. A major difficulty encountered in operating in situ combustion processes is low temperature oxidation (LTO), which involves oxygen addition reactions that occur at temperatures lower than 300 °CDATA [C. Typically, the byproducts of these reactions are oxidized hydrocarbons that have an increased polarity. This makes them more viscous, and thus detrimental to the in situ combustion process. Because of the major impact that LTO can have on the performance of an in situ project, a significant number of investigations have been carried out on the nature and effect of LTO reactions(2-27). In some circumstances, however, it may be beneficial to subject oil to LTO. The experimental results of Cram and Redford showed that air/steam combinations can provide better recovery rates and better thermal efficiencies than steam alone, at comparable volumes of steam injected, when the process is carried out in the low temperature oxidation region((28). It is believed that energy generation by the exothermic oxidation reactions is a significant factor in the LTO process.

A quick and inexpensive sample preparation method for AMS microfabric analysis in fine-grained sediment

Unless disturbed by postdepositional processes, sedimentary grain fabric reflects the physical conditions at the time of sediment deposition. Anisotropy of magnetic susceptibility, or AMS, is a sophisticated yet simple method for measuring grain fabric. In most cases this technique requires a self-supporting, right-cylindrical sample, and as a result unlithified sediment needs first to be lithified. Generally this is done with expensive, time-consuming resin impregnation procedures. In consolidated, mud-rich, clast-poor sediment, however, a new technique of cyclical steaming and (steam) soaking proved to be highly effective in softening the sediment sample enough so that it could be cored for AMS-sample preparation. Using this new method, samples were prepared in about 90% less time and for only 10% of the cost of standard impregnation techniques.

Research Methods Paper A Quick and Inexpensive Sample Preparation Method for AMS Microfabric Analysis in Fine-Grained Sediment

ABSTRACT Unless disturbed by postdepositional processes, sedimentary grain fabric reflects the physical conditions at the time of sediment deposition. Anisotropy of magnetic susceptibility, or AMS, is a sophisticated yet simple method for measuring grain fabric. In most cases this technique requires a self-supporting, right-cylindrical sample, and as a result unlithified sediment needs first to be lithified. Generally this is done with expensive, time-consuming resin impregnation procedures. In consolidated, mud-rich, clast-poor sediment, however, a new technique of cyclical steaming and (steam) soaking proved to be highly effective in softening the sediment sample enough so that it could be cored for AMS-sample preparation. Using this new method, samples were prepared in about 90% less time and for only 10% of the cost of standard impregnation techniques.

OptimizatioBl of a Mature Steam Flood Utilizing Horizontal Well?, Midway Sunset Fiend

Abstract Three short radius horizontal wells drilled in the steeply dipping Sub-Hoyt "E" sands of the Midway Sunset Field showed encouraging performance. These successes prompted a three-dimensional thermal simulation study to evaluate additional horizontal well potential and to optimize the remaining steam flood development. During this study, four medium radius horizontal wells were also drilled with very encouraging initial performance, All seven wells seem to perform within simulation and analytical expectations. This study improved the understanding of reservoir dynamics leading to a revised operating and development policy. Key conclusions are to place horizontal wells close to the oil-water contact, drill long horizontal laterals, and heat the oil in proximity to the horizontal wells. These give an optimum recovery, a more stable oil-water contact, and minimize water coning problems. Simulation results and additional field surveillance led to a revised field development plan currently underway in this mature steam flood. Introduction Historically, California's heavy oil fields have been developed with steam soaking and steam flooding of reservoirs developed with conventional, vertical wellbore. In 1990–1991, three short radius horizontal wells were drilled in the heavy of E sands of the Midway Sunset field to test their potential in mature thermal recovery projects. The success of these wells, described in detail in the literature(1), prompted a stimulation study to determine the potential long-term impact of horizontal wells on E sand reservoir management. Since the start of this study, four medium radius horizontal wells have been successfully drilled and produced in the E sands. Based on study recommendations and current success, horizontal wells should play a key role in the optimization of remaining E sand oil recovery as well as similar Midway Sunset reservoir. Geological Setting/Reservoir Description The Midway Sunset field is located in the southwest portion of the San Joaqun Basin in Southern California (Figure I). It is classified as a "super giant," with ultimate reserves of 440 million cubic metres. The majority of the field's production and reserves comes from Upper Miocene turbidite sand reservoirs. These sands were deposited in a series of interfingering submarine fans, and in some areas accumulated up to 460 m in thickness. As one of these fans. the Sub-Hoyt sands consist of massive to thin bedded unconsolidated sands and sandy conglomerates, interbedded with diatomaceous clays and siltstones. The E sands consist of amalgamated very fine to coarse grained sands which dip at 35 to 50 ° to the northeast (Figure 2). They have an average vertical thickness of 120 m, with a very high total net sand thickness to gross interval thickness ratio (N/G) of 0.85. The oil sands overlie an inactive aquifer. Production History The Sub-Hoyt E sands have produced 12 - 13 ° API crude since the early 1900's. Wells produced on primary until steam soaks were introduced in [ate 1966. Steam soaking was expanded through the mid 1970's to enhance the gravity drainage recovery mechanism. Steam flood pilots began on the L&H and Anchor leases in the late 1970's.

Enhanced Steam-assisted Gravity Drainage: A New Horizontal Well Recovery Process For Peace River, Canada

Abstract A new horizontal well recovery process, developed for application in the Peace River tar sands of Alberta, Canada, has shown sufficient technical and economic potential to warrant a field test which commenced operations in November 1993. The new process is an enhanced version of the steam assisted gravity drainage(1,2) (SAGD) process which is currently being field tested by Alberta Oil Sands Technology and Research Authority (AOSTRA) together with a consortium of industry members at the Underground Test Facility (UTF) located in northern Alberta(3–5). The SAGD well configuration, which consists of two parallel and superposed horizontal wells, with continuous steam injection occurring in the upper well and liquid and gas production from the lower well, is also utilized in the Enhanced Steam Assisted Gravity Drainage (ESAGD) process. A performance enhancement to the SAGD process is obtained through the application of a small pressure differential between adjacent pattern steam chambers. The gentle "steam drive," which occurs once sufficient bitumen mobility has been obtained between steam chambers, is observed to be tolerant of reservoir heterogeneities. Additional benefits include accelerated steam zone growth and bitumen production, up to 50% improvement in ultimate recovery efficiency, and no impairment to the thermal efficiency relative to the SAGO process. The surface access 'ESAGD field test currently underway in Peace River is described. The Peace River oil sands are 10caEed in northwestern Alberta (Figure I). Following the oil sand deposit discovery in 1949, Shell Canada began testing a variety of in situ recovery processes, including steam soak tests in 1962. steam drive and in situ combustion testing in 1965–66, followed by steam injectivity and productivity tests in 1973–74(6,7). A 31-well pilot (Peace River In Situ Pilot - PRlSP; see Figure 2) began operations in 1979, testing the pressure cycle steam drive process(7–9). Pilot operations ended in 1992 at a cumulative recovery efficiency of 65% and cumulative oil steam ratio of 0.25. In 1986, Shell Canada commenced operations in [he Peace River Expansion Project (PREP). the only commercial project in [he Peace River oil sands, with a target production of 1,600 m3/day of bitumen from 163 producers(10). The need to improve production economics by reducing production costs was the motivation behind the Peace River horizontal well study, which began in early 1991. The use of horizontal wells in a pattern steam drive was shown via numerical simulation to result in poor recovery and thermal efficiency due 10 poor steam conformance. This led to the numerical simulation study of SAGD (1,2). SAGD without any performance enhancements did not appear to yield the desired performance uplift in Peace River. Further study ultimately led to the development of the ESAGD process. Geological Description The Peace River oil sand deposit covers an area of approximately 6,200 square kilometres and contains some 12 billion cubic metres of bitumen. The productive horizon is found in the Bullhead member of the Cretaceous Bluesky/Gething zone at an average depth of 600 m, and is geologically equivalent to the shallower. productive McMurray sands in Northeastern Alberta(11).

CSS - Canada's Super Strategy For Oil Sands

Abstract The oil sands of Alberta represent a resource nearly as large (363x109 m3) as the world's conventional oil in place (about 450x109 m3; reserves 160x109 m3). Development of this resource to commercial production has been costly and time consuming. There are now at least two commercial in-situ projects - in Cold Lake and Peace River - producing over 10.000 m3/day of bitumen. Several pilots operations, such as UTF and HASDrive in Athabasca, are testing new technologies. We shall briefly talk about one of the commercially successful in-situ recovery methods - CSS, or Cyclic Steam Stimulation. CSS, as employed in Cold Lake, is quite different from the similar process (we'll call that conventional CSS) known variously as cyclic steaming, steam soak and huff n'puff in California, Venezuela, Indonesia and other heavy oil areas. Even there, the basic process varies from field to field because the reservoir drives and oil viscosities are different. CSS in the oil sands of Alberta has evolved over more than 30 years, based on steam parting in response to the peculiar reservoir conditions. rather than any ground-breaking innovation. Various papers have described CSS in other areas (e.g., Towson and Khallad's(1) paper on the Athabasca operations), but we shall primarily talk about the Cold Lake CSS. First let's look at conventional CSS as a basis for comparison. TABLE 1: Cold Lake project - phases 5 and 6 average performance forecast by cycle per well (from Esso's Application to ERCB, January 1985). (Available in full paper) Conventional CSS Conventional CSS is a field process discovered (Western Venezuela, 1959) and developed in the field. Experience in a given area is the key factor for success. The basic process is simple: steam is injected for two to three weeks, the well may then be shut in for a few days (soak period), after which it is put on production. The ensuing production is many times greater than the pre-stimulation rate, and even though production decline starts almost immediately, the rate may still be economic after six to 12 months. When the oil rate declines to a low level, the whole cycle - injection, soak, and production - is repeated, and this may be continued as many times as is economical. In some operations in California, more than 20 cycles have been conducted. The key performance index is the oil steam ratio (OSR), defined as the volume of oil produced per unit volume of water injected as steam (at standard conditions). The energy break-even OSR is about 0.07). The chief attraction of the process is quick payout: oil production starts within weeks, and also at a high initial rate. Notice that, as described above, conventional CSS is a single well operation, draining the oil in the circular hot zone formed during the injection portion of the cycle. Typically, the total oil produced declines from cycle to cycle, whereas the volume of water increases, as if the volume affected is only the original hot zone. How far this is the case would depend on many factors: oil viscosity, well spacing, shape of the hot zone, formation properties, geological factors, and particularly the reservoir drives.

A Statistical Analysis Of The Early Peace River Thermal Project Performance

Abstract A statistical correlation of well performance indices with geology is described for the steam soak phase of the Peace River Expansion Project (PREP), a thermal recovery project operated by Shell Canada Ltd. As expected from a confirmed, permeability-dominated steam underride through a basal lean bitumen zone, well performance correlates only with geology of the lean zone, and not at all with that of the overlying rich bitumen zone during this stage. However, the existence of extensive cross-correlations among the geological parameters, which in at least one instance has introduced a spurious correlation for calendar day oil rate, suggests that log analysis techniques need to be optimized in studies of this kind. In additionto the conventionally calculated bulk fraction shale volume Vsh)from logs, the introduction of other shale parameters is advantageous, and is discussed. Introduction In recent years there has been a growing interest in statistical studies of oil well performance indicators. Apart from the most common analyses, dictated by the need to reduce large data sets to some manageable size, statistical correlations of productiondata against geological parameters might be used to test theories of reservoir depletion that are provided by modelling. This work is intended to test a depletion theory, with the use of public data from the thermal Peace River Expansion Project (PREP), operated by Shell Canada Ltd. in northwestern Alberta. The PREP Project Shell Canada Ltd. has been operating the Peace River Expansion Project since 1986, following a very successful pilot which, as of October 1989, has recovered 53% of oil-in-place by a pressure cycle steam drive process(1). The project recovers bitumen from the 30 m thick Bluesky/Gething sands which have a thin basal zone of relatively low oil saturation (50% of pore volume) and high permeability. This lean pay zone, varying in thickness from 0.3 m to 7 m, allows injection of stream at high rates below fracture pressure in all but eight wells. All wells are perforated in this zone, except in Pads 12 and 15, where shale in the basal zone forced perforation in the rich zone, Thus, a permeability-dominated steam underride(2) permits heating or the richer zone from below(3). The operating strategy and facilities at the Peace River project have been described on several occasions(4–8); in essence it consists of alternating periods of high steam injection and low production rates (pressure-up) with periods of low or no steam injecrion and high production rates (blowdown). Figure 1 shows the well patterns at the Shell Peace River Project. To the west lies the original well cluster of the pilot (PRISP) project, consisting of seven inverted seven spots, Four clusters of thirteen patterns each represent the expansion project which will be considered in this paper. The small irregular "Multisoaks" pattern remains from a previous cyclic steam pattern. While the three eastern wells of this pattern have been incorporated into cluster A, they will be excluded owing to their prior operations history.

Steam-Soak Performance in South Oman

Summary With about 2 × 109 stock-tank m3 [12.6 × 109 STB] of medium/heavy oil originally in place (OOIP) in south Oman, considerable scope exists for increasing oil recovery by thermal methods. The viability of thermal recovery in south Oman was tested with a steamflood pilot in the Al Khlata sands of the Marmul field and a 2-year steam-soak project to test the applicability of steam soak in five south Oman oil fields producing heavy oil. This paper describes the performance of the latter project. The wells selected for the test program included a wide range of south Oman reservoir and oil characteristics—i.e., the main reservoir drive mechanisms of depletion, solution-gas, and edge- and bottomwater drive, the reservoir sandbody types, and oil viscosities from 80 to 4000 mPa·s [80 to 4, 000 cp]. Steam-soak operations were successful, and oil production accelerated significantly, with an average stimulated production rate twice that before stimulation. Acceleration was less marked in wells where reservoir energy is limited or where the primary (cold) water cut is more than 30%. At primary (cold) water cuts >50%, no increase in oil production rate was observed. The process was simulated numerically for several wells, with the results in close agreement with performance. Improved understanding of the process resulting from the simulation allowed the most important factors influencing performance to be identified and aided process optimization in the field test. Two small-scale steam-soak projects currently are being assessed for implementation in the early 1990's.