Shallow Heavy Oil Reservoir Research Articles

Simultaneous CO2 adsorption and conversion over Ni-Pd supported CeO2 nanoparticles during catalytic n-C7 asphaltene gasification

Shallow heavy oil reservoirs are suitable for the geo-sequestration of CO2 based on its adsorption and conversion during thermal-enhanced oil recovery processes. This study aims to evaluate multifunctional nanomaterials for CO2 adsorption and its subsequent transformation into valuable sub-products during the catalytic decomposition of asphaltenes in a steam gasification atmosphere. Three ceria nanoparticles with cubic (C-CeO2), orthorhombic (O-CeO2), and spherical (S-CeO2) shapes were tested in four stages including i) CO2 adsorption at 30, 50, 100, and 200 °C between 0.084 and 3.0 MPa, ii) dynamic in-situ CO2 adsorption in the presence of steam between 170 and 230 °C at 3.0 MPa, iii) dynamic in-situ CO2 adsorption in the presence of steam with adsorbed asphaltenes between 170 and 230 °C at 3.0 MPa and iv) CO2 conversion at the same conditions. The best nanoparticle morphology was doped with 1 wt% of Ni and Pd (C-CeNiPd) and was tested in the same experiments. Among the most important results, CO2 adsorption increased in the order S-CeO2 < O-CeO2 < C-CeO2 < C-CeNiPd, regardless of the temperature. When steam was injected, CO2 adsorption is reduced in all the systems. At 200 °C adsorption decreased by 3.0 %, 2.7 %, 2.5 %, and 2.0 % in processes assisted by S-CeO2, O-CeO2, C-CeO2, and C-CeNiPd, respectively. Nanoparticles with adsorbed asphaltenes presented a high tendency for CO2 adsorption as well. The nanoparticle with the best morphology (C-CeO2) adsorbed about 24.3 % (3.92 mmol) of CO2 at 200 °C, and the yield increased after doping with Ni and Pd, obtaining CO2 adsorption of 34 %. Finally, for CO2 conversion, a mixture of gases composed of CO, CH4, H2, and light hydrocarbons (LHC) is obtained. The hydrogen production content follows a trend that agrees well with each material's adsorptive capacity and catalytic activity. The maximum %vol of H2 produced at 200 °C during asphaltene gasification was 31 %, 29 %, 24 %, and 23 % for C-CeNiPd, C-CeO2, O-CeO2, and S-CeO2, respectively.

Comparison of Foamy Oil Behaviour between Shallow and Middepth Heavy Oil Reservoirs in the Orinoco Belt

Nowadays, extra heavy oil reservoirs in the Orinoco Heavy-Oil-Belt in Venezuela are exploited via cold production process, which present different production performance in well productivity and primary recovery factor. The purpose of this study is to investigate the causes for such differences with the aspect of foamy oil mechanism. Two typical oil samples were adopted from a shallow reservoir in western Junìn region and a middepth reservoir in eastern Carabobo region in the Belt, respectively. A depletion test was conducted using 1D sand-pack with a visualized microscopic flow observation installation for each of the oil samples under simulated reservoir conditions. The production performance, the foamy oil behaviour, and the oil and gas morphology were recorded in real time during the tests. The results indicated that the shallow heavy oil reservoir in the Belt presents a weaker foamy oil phenomenon when compared with the middepth one; its foamy oil behaviour lasts a shorter duration with a smaller scope, with bigger bubble size and less bubble density. The difference in foamy oil behaviour for those two types of heavy oil reservoir is caused by the difference in reservoir pressure, solution GOR, asphaltene content, etc. Cold production presents obvious features of three stages under the action of strong foamy oil displacement mechanism for the middepth heavy oil reservoir, which could achieve a more favourable production performance. In the contrary, no such obvious production characteristics for the shallow heavy oil reservoir are observed due to weaker foamy oil behaviour, and its primary recovery factor is 9.38 percent point lower than which of the middle heavy oil reservoirs.

Large-scale triaxial experimental investigation of geomechanical dilation start-up for SAGD dual horizontal wells in shallow heavy oil reservoirs

There are only a few related studies focused on the steam assisted gravity drainage (SAGD) dilation start-up technology (termed as dilation start-up in this paper), especially with true triaxial stress physical modelling experiments in the laboratory. Therefore, in order to better understand the dilation start-up process, four large-scale (1050 mm × 410 mm × 410 mm) true triaxial experiments of SAGD start-up with dual horizontal wells were conducted for the first time by using the oil sands from the Xinjiang oilfield, northwest China. The dilation process characterized by temperature changes at different positions inside the experimental samples was monitored in real time. The performance differences between dilation start-up and conventional start-up were discussed in detail, and the effects of dilation pressure and dilation time on the dilation process were also studied. The experimental results indicate that dilation start-up can significantly reduce the well communication time between injector and producer, and enhance the range of dilation zone and improve the uniformity of dilation zone along the horizontal wellbores. Moreover, we find that dilation pressure is an essential factor influencing the dilation effect. The average communication parameter increases by 5% if dilation pressure increases by 10% whereas the standard deviation of communication parameter decreases. The evolution of dilation zone with time shows that long-time dilation prompts the uniform propagation of dilation zone along the horizontal wellbores. This study provides guidance for the optimization of SAGD dilation start-up in shallow heavy oil reservoirs.

The Philosophy of Enhanced Oil Recovery

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 196362, “Philosophy of EOR,” by Tayfun Babadagli, SPE, University of Alberta, prepared for the 2019 SPE/IATMI Asia Pacific Oil and Gas Conference and Exhibition, Bali, Indonesia, 29-31 October. The paper has not been peer reviewed. Despite the substantial investment dedicated to research-to-pilot scale investigations, the ultimate profit from enhanced oil recovery (EOR) applications has been below expectations since the 1980s (less than 10% of total production). The author writes that revisiting and challenging the knowledge and dogmatic assumptions gathered during 5 decades of EOR is necessary. In the complete paper, a philosophy for the future of EOR projects is developed through a series of questions that applies to the industry’s transition from completion of conventional EOR toward unconventional EOR. Why Are We Afraid of EOR? The underperformance of EOR may be explained by the following reasons: Limitations in capturing the physics of the process for proper technical and economical assessment Risks involved in field pilots Securing the supply of the materials injected Difficulties involved in EOR design Risk resulting from economic uncertainties Why Are There Fewer EOR Projects Than Desired? True Drivers of EOR Applications, Technology, and Economics. Once the technical viability of an EOR project is proven, cost-effective applications can be achieved by the high-quality optimization efforts of engineers who can decide the appropriate optimization methods or at least the conditions under which a project can turn profitable. Insufficient Attention Given to Cost-Efficient EOR Methods. Use of air as the cheapest EOR agent has been investigated substantially for field-scale projects, but its applications are still limited. Recently, air injection was demonstrated to be safe under the low-temperature oxidation process and at atmospheric pressure/temperature conditions such as those of shallow heavy-oil reservoirs. Microbial injection also offers promising possibilities as a cost-effective approach. Fear of Most-Expensive Miscible Processes. The most-expensive EOR agents are miscible gases, or solvents, which are expected to yield the highest recovery under suitable conditions. Recyclability of the injected material from the miscible injection is an attractive part of the EOR process; however, unrecovered injectant can also be a critically limiting factor. Exploiting gas as a byproduct from other operations, however, allowed sustainable EOR development in Alaska (Prudhoe Bay), the North Sea, and Canada (Zama).

Experimental investigation on the SAGD dilation start-up in shallow heavy oil reservoirs

There are few related researches focused on the steam assisted gravity drainage (SAGD) dilation start-up technology (termed as dilation start-up in this paper), especially with physical modelling experiments. Therefore, in order to better understand the dilation start-up process, several large-scale experiments of SAGD start-up with dual horizontal wells were carried out by using the oil sands from Xinjiang oilfield, northwest China. The dilation process characterized by temperature changes at different positions inside the experimental samples was monitored in real time. The performance differences between dilation start-up and conventional start-up were discussed in detail, and the effects of dilation pressure and dilation time on the dilation process were also studied. The experimental research indicated that dilation start-up can significantly enhance the range of dilation zone and improve the uniformity of dilation zone along the horizontal wellbores. Moreover, it was found that dilation pressure is an essential factor influencing the dilation effect, in that the size and distribution of dilation zone are largely dependent on dilation pressure. The evolution of dilation zone with time shows that a long-time dilation prompts the uniform propagation of dilation zone along the horizontal wellbores.

浅层常规稠油油藏筛管完井水平井高含水综合治理技术

浅层常规稠油油藏筛管完井水平井高含水综合治理技术

Study on the method for determining the effective construction range for heavy oil cold mining chemical viscosity reduction

ABSTRACT Compared to the area of shallow heavy oil reservoir with severe heterogeneity and fault development with the poor effects of thermal recovery during viscosity reduction construction, chemical viscosity reduction is a promising solution in cold production. Based on the seepage resistance characteristics of heavy oil in porous media and reservoir engineering, this thesis analyses the effective radius for chemical viscosity reduction. Finally, based on the result that the threshold pressure gradient that retards the heavy oil flow is equal to the driving pressure gradient of the well depending on the formation pressure, the maximum chemical viscosity reduction radius (rmax ) is determined; considering whether the crude oil contains dissolved gas as the first boundary, if the reservoir contains dissolved gas within the first boundary, the construction range increases to the second boundary as the viscosity of crude oil changes from degassing. The minimum distance to the wellbore is determined by these two boundaries such that when the saturation pressure is less than the flow pressure (Pb ≤Pwf ), there is no minimum distance to the wellbore for crude oil without dissolved gas. When Pb≥Pwf , the minimum radius is dictated by the radius under saturated pressure rb = rmin . On the basis of the theoretical method, this radius of construction is applied to the field test. After adopting a construction design based on the cold chemical viscosity reduction calculations, oil mining increased by 2.5 t daily in the three months of open well production. The success of this field test proves that the theoretical method is practical and can enhance the success rate of field application of heavy oil mining via cold chemical viscosity reduction technology.

Phase Behavior Measurements and Modeling for N2/CO2/Extra Heavy Oil Mixtures at Elevated Temperatures

Recently, a new technology, the so-called multithermal fluids huff and puff, to exploit extra heavy oil reservoirs has been applied successfully in several shallow heavy oil reservoirs in China. However, the use of this technology in deep extra heavy oil reservoirs is rare. Successful application of this technique in deep extra heavy oil reservoirs requires a good knowledge of the phase behavior and physical properties of multithermal fluids and extra heavy oil mixture. The major components of multithermal fluids mixtures are steam, N2, and CO2. In this work, targeting the application of multithermal fluids injection in heavy oil reservoirs, we conduct PVT experiments on the N2/CO2/heavy oil mixtures under deep reservoir conditions and develop equation of state models for representing these PVT data. Experimentally, it is found that CO2 solubility in extra heavy oil decreases with an increasing temperature at given pressure. Contrary to CO2, N2 solubility in extra heavy oil increases with an increasing te...

江37区蒸汽驱数值模拟开发规律研究

本文以大庆江37区为例，利用CMG软件内的STARS热采模块对浅薄层稠油油藏进行蒸汽吞吐数值模拟开发动态规律研究，对蒸汽驱转蒸汽吞吐参数优化，主要包括对转蒸汽驱时机、注汽井注汽速度、井底蒸汽温度与压力的优选，并得出转蒸汽驱推荐方案，对于提高稠油油藏的采收率具有一定的指导作用。 Taking Daqing Jiang 37 Block as an example, the study on the dynamic regularity of steam throughput in shallow heavy oil reservoirs with STARS heat mining module in CMG software is carried out. Meanwhile, parameter optimization for steam drive to steam soak is carried out, in-cluding the timing of steam flooding, the steam injection rate of steam injection well and the optimization of steam temperature and pressure at the bottom hole, and the recommendation scheme of turning to steam drive is obtained, which is significant to improve recovery of heavy oil reservoirs.

English

&nbsp; This paper presents an integrated study on the superheated steam injection in the North Кенкияк Field, Kazakhstan. The methodologies cover investigation of mechanisms of superheated steam in recovery, lab experiment, and numerical simulation. The study indicates that the injection of superheated steam can cause rock wettability conversion which is favorable to recovery. The higher the heat enthalpy, the larger the specific volume and latent heat of vaporization of superheated steam would result in the better production and economic performance. The study result was further conformed in the pilot test. Field fulfillment is optimized and scheduled. &nbsp; Key words:&nbsp;Superheated steam, shallow heavy oil reservoir, heatloss, reservoir simulation.

Research and Application of Thermal Insulation and Injection-Production Process Technology in the Shallow and Thin-Bedded Heavy Oil Reservoirs

In view of Shallow and Thin-Bedded Heavy Oil Reservoirs, it belongs to the forbidden zone which can not be developed by the internationally recognized. To reduce the cost of well drilling and well completion, Φ139.7 mm casing is adopted in well completion. In the early Pilot test, there were many problems in steam injection with blank tubing, low thermal efficiency of steam injection, casing and cement mantle damaged seriously, and even as worse as well abandonment. To solve the problems, the Insulated and Injection-Production integration tubing string was designed by the Y341-115 insulation packer and other supporting tools, which can solve wellbore heat insulation and reverse circulation well cleanup in production. It carried out the function that multicycle steam injection and production can be integrated in one-trip. The large scale application showed that the effect of heat insulation was remarkable, which reduced the production cost, made the shallow and thin-bedded heavy oil reservoirs develop economically and effectively.

Spectrum: Moving Toward 70% Recovery Factor: Multiple Disciplines, Different Methods, One Goal

President's column During my 38 years in the industry, I have been dedicated to reservoir and well productivity improvement, particularly focused on enhanced oil recovery (EOR). As many of you know, I have talked about our industry’s need to increase recovery during my many section and conference presentations and have written numerous papers on the topic. I feel that productivity improvement is both one of the industry’s biggest challenges and one of its most promising opportunities, and it is a constantly moving target. The world’s desire for energy will continue to grow. By 2030, our global challenge will be to meet a projected 40% increase in energy demand and to do so in a way that protects the environment. The often-quoted industry average of 35% recovery efficiency for conventional crude oil raises the question: Can we double it to produce several trillion barrels more? The many technology breakthroughs and thousands of incremental advances in exploration and production since the beginning of oil production have increased oil recovery levels in many shallow heavy oil reservoirs from less than 10% to in excess of 70% by steam injection. We can add 600 to 900 billion bbl of recoverable oil with only a 10% incremental recovery of oil from the remaining conventional resource base by improved recovery through improved oil recovery (IOR) and EOR technologies. Although by no means an easy task, if we can raise total recovery to 70%, we can add a few trillion bbl of recoverable oil. The future will be even brighter if we can use IOR and EOR in exploiting unconventional resources, with the potential to defer the impact of “peak oil” far off into the future. Enormous progress is already taking place through the integration of unconventional resource exploitation with horizontal drilling and multistage fracturing. As a result, US oil production is on the rise for the first time in many decades, primarily due to liquids from unconventional reservoirs. Now, I know what many of you are going to say: “A 70% recovery efficiency cannot be achieved.” I believe it can be. Such efficiency gains are happening today. Many operators are improving recovery efficiencies by being innovative and infusing more technology and know-how, increasing capital, and working with regulators. It is not unreasonable to imagine that implementing advanced IOR and EOR technologies can create another step change for this game-changing resource. When we start thinking of the integration of unconventional resources with the potential of IOR and EOR, the possibilities are mind boggling. The challenge we must face is how to accelerate innovation and the development of essential technology. Commercializing technology in the oil and gas market is costly and time intensive, with an average of about 16 years from concept to widespread commercial adoption. The key is more collaboration in R&amp;D and sharing innovations among industry, governments, and academic institutions, as well as with scientists outside the E&amp;P industry. We must continue to expand our capabilities through innovation as our industry has relentlessly done in the past.

Seismoelectric response of heavy oil reservoirs: theory and numerical modelling

We consider a linear poroelastic material filled with a linear viscoelastic solvent like wet heavy oils (oil as opposed to water or brines is wetting the surfaces of the pores). We extend the electrokinetic theory in the frequency domain accounting for the relaxation effects associated with resonance of the viscoelastic fluid. The fluid is described by a generalized Maxwell rheology with a distribution of relaxation times given by a Cole–Cole distribution. We use the assumption that the charges of the diffuse layer are uniformly distributed in the pore space (Donnan model). The macroscopic constitutive equations of transport for the seepage velocity and the current density have the form of coupled Darcy and Ohm equations with frequency-dependent material properties. These equations are combined with an extended Frenkel–Biot model describing the deformation of the poroelastic material filled with the viscoelastic fluid. In the mechanical constitutive equations, the effective shear modulus is frequency dependent. An amplification of the seismoelectric conversion is expected in the frequency band where resonance of the generalized Maxwell fluid occurs. The seismic and seismoelectric equations are modelled using a finite element code with PML boundary conditions. We found that the DC-value of the streaming potential coupling coefficient is also very high. These results have applications regarding the development of new non-intrusive methods to characterize shallow heavy oil reservoirs in tar sands and DNAPL contaminant plumes in shallow aquifers.

Investigation of a Stochastic Optimization Method for Automatic History Matching of SAGD Processes

Abstract Western Canada has large reserves of heavy crude oil and bitumen. The Steam-Assisted Gravity Drainage (SAGD) process that couples a steam-based in situ recovery method with horizontal well technology, has emerged as an economic and efficient way to produce the shallow heavy oil reservoirs in Western Canada. Numerical reservoir simulation is used to predict reservoir performance. However, prior to the prediction phase, integration of production data into the reservoir model by means of history matching is the key stage in the numerical simulation workflow. Research and development of efficient history matching techniques for the SAGD process is important. An automated technique to assist in the history matching phase of the SAGD process is implemented and tested. The developed technique is based on a global optimization method known as Simultaneous Perturbation Stochastic Approximation (SPSA). This technique is easy to implement, robust with respect to non-optimal solutions, can be easily parallelized and has shown an excellent performance for the solution of complex optimization problems in different fields of science and engineering. The reservoir parameters are estimated at reservoir scale by solving an inverse problem. At each iteration, selected reservoir parameters are adjusted. Then, a commercial thermal reservoir simulator is used to evaluate the impact of these new parameters on the field production data. Finally, after comparing the simulated production curves to the field data, a decision is made to keep or reject the altered parameters tested. This research is preliminary. Although the results are not ready for commercial implementation, the ideas and results presented here should prove interesting and fuel development in this important subject area. A Matlab(1)code, coupled with a reservoir simulator, is implemented to use the SPSA technique to study the optimization of a SAGD process. A synthetic case that considers average reservoir and fluid properties present in Alberta heavy oil reservoirs is presented to highlight the advantages and disadvantages of the technique. Introduction The Simultaneous Perturbation Stochastic Approximation (SPSA) methodology(2) has been implemented in optimization problems in a variety of fields with excellent performance. This paper considers production data integration in reservoir modelling for Steam-Assisted Gravity Drainage (SAGD) processes by automatic history matching with SPSA. Automatic history matching problems are optimization problems that must find the minimum of an objective function. The efficient determination of the gradient of the objective function is one of the most important aspects of the overall efficiency of an optimization methodology. For some cases, it is easy to obtain the gradient of the objective function and the application of 'gradient-based' methods for the solution of the optimization problem is the natural choice in these circumstances. However, for many practical problems, it is time-consuming and expensive or simply impossible to estimate the gradient of the objective function. The notion of 'gradient-free' methods is introduced to overcome this problem. As a method in this category, SPSA provides a powerful technique for automatic history matching. In this work, the objective function related to a synthetic SAGD case is defined for automatic history matching.

Cold Production And. Enhanced Oil Recovery

Introduction Economical heavy oil production is possible by allowing formation sand to be produced along with fluid. Cold production has potential to increase subsequent enhanced oil recovery (EOR) efficiency, operating new technological possibilities for continuedeconomical oil production from these reservoirs. Heavy oil (10–15 ºAPI) in cohesionless sandstones (&amp;gt;30% porosity) can be exploited by permitting sand to enter the wellhole along with fluids. Information from Lloydminster and North Primrose areas is given in Table 1. To achieve sustained production, sand production must be encouraged through use of closely spaced high-energy perforations and through application or work over strategies that re-initiate sand production if it has stopped. Sand exclusion is disastrous; free sand flow is vital production mechanism, as yet incompletely understood(1). Blocking it by gravel packs or screens simply reduces the oil now below economical levels. Lowering Cold Production Costs To compete with offshore oil and absorb price differences between heavy and conventional oil production cost minimization is vital for the shallow (300 – 800 m) heavy oil reservoirs typical of Alberta and Saskatchewan Cretaceous deposit. Drilling costs can be lowered by using coiled tubing and smaller diameter drill hole; there is little evidence that a larger hole is better for cold production. Workover costs can be lowered by using better pumps that do not sand in, and by better workover methods to reduce service TABLE 1: Enhancement of oil rate through cold production. Table Available In Full Paper. rig time and re-establish sand production. Economic and environmentally acceptable sand disposal methods must be implemented(2). Finally, initial development must be planned with EOR production in mind to minimize additional redevelopment costs. Cold Production Mechanisms In these wells, conventional well theory predicts production rates of 0–2 m3/day, rather than the 5– 15 m3/day commonly obtained. Why does heavy oil flow more efficiently if 1–3% sand enters the wellbore with the fluids? A complete answer remains elusive, but the four major factors are likely enhanced drainage radius, grain movement, gas bubble expansion and continuous pore deblocking. Quantitative analyses have been developed for the first two(3, 4), and partly for the third mechanism(5). The fourth remains a qualitative concept. Enhanced drainage arises because thousands of cubic metres of reservoir are affected by large-scale sand production. Discrete cavities may exist, piping tubes may develop, and zones dilated from 30% to 36–40% porosity may all accompany massive sand production. Each of these will increase well flow capacity. Closed-form solutions for piping tube or general yield models show that a factor of 3 to 4 in sustained rate productivity can be expected (3). However, improvement factors of 4 to 10 and more are common in cold production. Grain mobility facilitates liquid movement, independent of permeability enhancement effects. A theoretical model of local fluid rate enhancement in mobile grain systems shows that increased flow rates up to a factor of two can be expected because of the reduction of drag forces(4). There is a variant of the gas bubble theory which may help explain improved production(5).

Theory of oil detachment from a solid surface. In situ emulsification and enhanced production of heavy oils by a novel “chemical huff-and-puff” method

Criteria for oil detachment have been established theoretically and presented in dimensionless form. All parameters included in these expressions can be measured directly. It is shown that oil detachment (from solid) may be the major factor controlling in situ emulsification of heavy oils. A new model for enhanced oil recovery by chemical (surfactant) flooding has been developed. This model takes into consideration the oil detachment from the rock, the oil displacement from porous media, and the oil recovery from the wellbore. A novel and economical method for enhanced production of heavy oil has been designed theoretically tested in the laboratory and demonstrated in the field. This method involves injection of an aqueous surfactant formulation into a shallow heavy oil reservoir at ambient temperature (“huff”) and removing the emulsion formed in situ (“puff”) through the same well. The “huff and-puff” cycle can be repeated several times by re-injecting the chemicals after demulsification and recovery of the viscous oil. Peculiarities of this process have been evaluated quantitatively.

Thermal Recovery In The Venezuelan Heavy Oil Belt

Abstract This paper describes a successful cyclic stea1n injection program in the Jobo Field, located on the northeastern edge of the Venezuelan Heavy Oil Belt. The program was commenced in 1974 by Amoco International Oil Company. It is being continued, following reversion, by Amoven, S.A., a subsidiary of Petroleos de Venezuela. The Jobo reservoirs are highly unconsolidated sandstones at a depth of approximately 3,800 feet. The crude gravities range from 9 to 13.5 °API. Wells were completed on 64-acre spacing utilizing techniques designed to withstand thermal processes. A portable steam generator rated at 30 MMBtu per hour is used and the steamed wells have received between 4,000 and 8,000 metric tons each. This corresponds to between 150 and 200 MMBtu per foot of pay. The wells are placed on production after soak periods varying from one week to one month. In the eleven wells which have been steamed at this writing, peak oil producing rates ranging from two to five times the pre-steam rates have been realized almost immediately on commencement of production. The techniques described herein have permitted injection of high-quality steam at appreciable depths while avoiding m.ost of the common problems normally expected, such as bottom-hole equipment failures, casing cement and liner failures, and surface equipment malfunctions. Introduction STEAM STIMULATION is a well-established technique developed in the early sixties. It has found extensive application in Venezuela, mostly in shallow heavy oil reservoirs ranging in depth from 300 to 3,000 feet and containing oil of moderate gravity ranging from 14 ° to 20 °API. Success has been notable in several areas, mostly along the Juseping trend in eastern Venezuela and the Bolivar Coast on the eastern shore of Lake Maracaibo. The technique has not been very successful where the reservoir and crude oil properties vary appreciably from the ranges given above. This is the case in the northern portion of the Orinoco Heavy Oil Belt; the reservoir depth is between 3,600 and 4,000 feet, the oil viscosity averages 1,800 SFS and the oil gravity ranges between 8.5 and 13 °API. This paper describes a successful steam stimulation project in the Jobo Field, located on the extreme northeastern edge of the Orinoco Heavy Oil Belt. The project is notable as a demonstration of the successful application of steam stimulation under conditions of extreme depth, viscosity and gravity. Field Description Figure 1 is a map of Venezuela, showing the location of the Jobo Field with respect to the vast Orinoco Heavy Oil Belt. The heavy oil belt contains some 700 billion barrels of oil in place, but has seen only scattered development on the extreme northern fringe. Jobo underlies a 5,500-acre concession originally granted to Amoco Venezuela Oil Company and now under the administration of Amoven, S.A., a wholly owned subsidiary of Petroleos de Venezuela, S.A. The productive Oficina Sandstone at Jobo is separated into two distinct reservoirs, designated Group I and II.