We present two versions of a Darcy-scale model for simulation of the solution gas drive in heavy oils.
Presence and behaviour of a foamy-oil effect appears to be critical to the cold production process. This process is not a well-understood production mechanism because a wide range of different petrophysical parameters and experimental factors interact in a rather complex way. Over the past few years, a number of efforts have been made, in many institutions, in order to understand and model the solution gas-drive mechanism in primary heavy oil recovery. Conventional simulations succeed in matching actual field productions but are not reliable for prediction forecast purposes (large uncertainties on recovery factors). We present an evolving nucleation and flow model for solution gas drive in heavy oil.
The model is built at the Darcy scale and involves the effect of capillarity on bubble flow and phase change. An ad hoc simulation tool is built to analyze carefully the properties of the model. The tool allows to reproduce laboratory experiment across a sample rock.In the limit of infinitely slow depletion, an asymptotic theory is constructed that allows to predict analytically the pressure difference across a sample. The theory predicts a pressure gradient at first order without additional calculation, and the gradient appears, at first order, independent on the gas formation (degassing) kinetics. No saturation gradient is predicted at first order. The results are compared to numerical simulations and experiment, and good agreement is found in cases where the pressure gradient is known.
In a second version of our model we introduce the effect of capillarity on bubble growth. Capillarity delays bubble growth by stabilizing small bubbles under a certain critical radius. This new term leads to nucleation fronts propagating rapidly through the sample.
It appears more difficult to predict a saturation gradient. The causes of this difficulty are analyzed.
Many efforts have been made recently to understand and model the solution gas drive mechanism in primary heavy oil recovery. Present day models are unreliable, as even though conventional simulations can succeed in matching field productions, they fail to capture the actual physics of the solution gas drive process in heavy and extra-heavy oils. A "foamy-oil" effect related to the bubbly aspect of recovered oil, enhanced oil recovery and higher critical gas saturation has been identified by some authors5,9 but its physical nature is not quite elucidated.
In order to better understand the physics of solution gas drive, several experiments have been conducted at the laboratory scale. In this work we attempt to simulate the experiments reported by Bayon et al.[1,2] .The flow rate is imposed so that the pressure decreases in an approximately linear fashion over the duration of the experiment. These experiments were performed under X-ray scan to record the saturation profiles all along the core during the depressurization.
It was attempted to model the results of the experiment using both classical Darcy scale models such as those of the Stars® and Eclipse® simulators, and a modified model. Two main difficulties arose
(a) Relative permeabilities have to be adjusted as a function of the rate of decrease of the pressure or depletion rate. In other words, relative permeabilities matched for one depletion rate do not match the results for the other depletion rate. This is a classical difficulty in heavy oil modeling.
(b) Measured saturation profiles differ from simulated ones. The measured profiles have marked spatial variations or gradients (this was observed by Egermann et al., Sahni et al., as well as by Bayon et al.[1,2] whose data are reproduced here on Figure 1). On the other hand the simulated profiles are flat. This effect has been confirmed with other models and codes
Giant, geologically complex heavy oil fields can take decades to develop, sodevelopment decisions made early in the life of the field can have long-rangeimplications.Decision and risk analysis (D&RA) is often used to makedecisions that will maximize risk-adjusted economic benefit.Unfortunatelyin large heavy oil fields, D&RA can be very challenging due to the largenumber of variables and the endless number of development and expansionscenarios to analyze.The time needed to complete a D&RA can becomeprohibitive when full-field reservoir simulation is the main tool forforecasting primary production and well count, with one simulation taking manyhours or days to complete.
This paper describes two new simulation tools developed to overcome thesechallenges: 1) a method for populating a model with hundreds-to-thousands ofhorizontal wells, and 2) a method to quickly and directly optimize expansiondecisions.
A semi-automated spreadsheet-and-simulation method was developed to quicklyplace and select hundreds-to-thousands of hypothetical/future horizontal wellsin a multi-million grid- block model.Because the method automaticallyaccounted for all model static properties and their effects on dynamicproduction response, the hypothetical wells had productivity characteristicsvery similar to actual drilled wells placed in the model.
A multi-variant non-linear interpolation method was developed that enabledfull-field forecasts - for any combination of acreage allocation, well count,drilling order, and expansion rate constraint - to be calculated in less than 5seconds, compared to about 20 hours for traditional simulation.Extensivevalidation work showed that well count and production curves from thespreadsheet virtually overlaid those obtained using traditional simulation ofthe particular expansion scenario.Such close agreement was possiblebecause the basis of the spreadsheet forecast was utilization of traditionalsimulation forecasts from a handful of relevant cases.
A key breakthrough beyond just fast forecasting was the coupling of thefollowing three components inside the same spreadsheet: the fast forecastingmethod, calculation of an economic indicator/objective function (NPV), andcommercial optimization tools.This linkage made possible, perhaps for thefirst time (at least at this scale), realization of direct optimization of anydevelopment scenario in a matter of minutes to a few hours, depending on thenumber of variables being optimized.
Fresh water scarcity and increasing demand are worldwide concerns and arebeing addressed by a number of water man-agement initiatives in Alberta andCanada.In 2003, 0.3 bil-lion m3 of produced water was injected intodisposal wells associated with oil and gas production in Alberta.Thisvol-ume of water is a potential resource for recycling and benefi-cial reuse inAlberta, which would have a significant impact on sustainable development inAlberta. This water must first be treated to meet water qualityrequirements and regulatory guidelines for specific applications.Thispaper provides a comprehensive technical and economic review of watertreat-ment technologies and shows that water treatment processes arecommercially available.Although the cost of implement-ing suitabletreating processes to meet drinking water quality guideline is estimated atthree times the current cost of mu-nicipal water supply in Alberta, it is morefeasible to recycle produced water for other purposes, such as agricultural orpe-troleum application (i.e., waterflooding, etc.).This is because waterquality guidelines for most other applications are not as stringent as that fordrinking water and there is increasing pub-lic resistance for industry to usefresh water for commercial applications. A multi-disciplinary researchand development team studying water recycle and beneficial reuse is necessaryto look into these issues. The University of Calgary is set tocollaborate on such projects due to the current research em-phasis onsustainable energy and environmental impact. Col-laboration between thegovernment, industry and academia to develop initiatives aimed at reducingfresh water is possible in Calgary for several reasons.One is theproximity of many major oil and gas companies in this city, which would allowfor easy communication.Another is the fact that the current price of oilwould not inhibit producing companies from in-vesting in this kind ofresearch.The result can be well-developed initiatives to treat andrecycle produced water for beneficial reuse, thus reducing fresh water demandfor many applications in the petroleum and agricultural industries.
Geostatistical reservoir modeling provides multiple equally probable realizations of structure, facies, and petrophysical properties.A large number of realizations should be processed to ensure that production decisions and strategies are not unduly affected by an unusually good or bad simulated realization.Flow simulation, however, often requires significant computational and professional time.Only a few geostatistical realizations can be subjected to detailed flow modeling.An integrated approach is developed for ranking geostatistical realizations.A small number of representative realizations can then be selected for flow processing.
The ranking and selecting of realizations must be tailored to the flow process.Techniques that work for conventional oil and gas reservoirs are not necessarily suitable for in-situ and SAGD bitumen recovery methods.This paper describes static connectivity measures tailored to heavy oil recovery processes from the McMurray Formation.Flow simulation is performed on many geostatistical realizations to calibrate the ranking measures to production response.This permits reliable inference in reservoir areas where it is not possible to perform many flow simulations.
This case-history paper presents the development background and detail of optimized procedures followed to plug and abandon wells in a cyclic-steam well in central California.Improvements that resulted in the success are detailed and explained.
Abandonment processes included identification, using tilt-meter events, of holes in casing and/or casing parting. Temperature surveys and/or radioactive surveys confirmed and located depth of the hole in the casing. Specific procedures were then followed to abandon the well below the part, at the part, and then above the part in the casing. Inspection and testing of the casing were also conducted to help ensure that additional holes were not present in the casing before the abandonment was complete. In the rare instances that additional holes were found, they were squeezed off separately with cement. Key to the success of this procedure was squeezing thixotropic cement instead of setting balanced plugs across zones of interest. This method allowed for short turn-around times to resume operations and helped ensure that the cement remained where it was originally placed.
The solvent based recovery process "Vapex" has a great potential for therecovery of heavy oil and bitumen resources, due to the low energy intensityand reduced GHG emission associated with the process. The process has beenextensively investigated in the laboratory models and through numericalsimulation studies. This has indicated the technical viability of the processas an alternative to thermal recovery processes, viz. SAGD. In the last fewyears several proprietary pilot has been developed to establish the commercialviability of this concept.
The most important uncertainty about this process is the rate of mixing ofsolvent molecules with high viscosity hydrocarbons. Due to low moleculardiffusivity the theoretical predictions of extraction rates are significantlylower than the SAGD process. However, the results of physical modelexperimental carried out by this author showed a considerably higher masstransfer rate at the solvent bitumen interface. The process, whether in thelaboratory model or in the reservoir porous media, takes place in a microscopiclevel. An experimental evidence of this phenomenon will be presented in thepaper.
Transferring this microscopic phenomenon into a macroscopic simulation modelpresents a serious challenge. Artificially higher diffusion or dispersioncoefficients are used to match the experimental data. Even with that both theproduction rate and the solvent saturation profile can not be matchedsimultaneously. For example the higher dispersion coefficient results in deeppenetration of the solvent, resulting in a diffusion zone, thicker than theexperimentally determined value. Lower dispersion coefficient results in alower production rate. Some of these simulation results are presented in thispaper. A recent development in the simulation model, Dynamic Grid Refinement,improves the simulation match by allowing the use of smaller grid blocks at thediffusion boundary layer.
As a result of hydrothermal stress induced by steam injection in reservoirs, heavy crudes undergo chemical transformations, called aquathermolysis, the extent of which depends at least on steam temperature, injection history and both crude and mineral matrix physicochemical properties. As heavy crudes often have high sulfur content, their hydrothermal alteration results in the formation of H2S. In order to predict artificial H2S emissions during thermal EOR, we seek to develop a geochemical model to be coupled with a 3D reservoir simulator.
This paper presents the first step of the process that consists in simulating in-situ aquathermoysis in laboratory in order to derive a 0D compositional kinetic model for H2S formation.
For that purpose, aquathermolysis experiments were performed on an Athabasca oil sand sample. The amount of H2S generated during aquathermolysis was measured for different time and temperature conditions. At the same time, sulfur distribution was quantified over crude SARA fractions (Saturates, Aromatics, Resins and Asphaltenes) and insoluble fraction (mainly mineral), before and after aquathermolysis. Experimental results were then derived to elaborate a kinetic model of H2S generation upon aquathermolysis, encompassing the chemical conversion of sulfur in SARA and insoluble fractions.
Steam and hot water assisted recovery from heavy oil reservoirs can induce physicochemical interactions between water, oil and rock. As a result, significant amounts of hydrogen sulfide, together with carbon dioxide, may be generated, increasing the risk of corrosion, health security problems and environmental aggression during production (Burger et al., 1985; Mohammed et al., 1990; Thimm, 2001).
Aquathermolysis is defined as the sum chemical reactions between heavy oil and steam (Hyne et al., 1984; Hoffman et al., 1995). Aquathermolysis laboratory experiments were previously carried out, either on isolated heavy crude (Hyne and Clark, 1981), or on whole core samples (Akstinat, 1983; Hyne et al., 1984; Attar et al., 1984; Monin and Audibert, 1988; Hoffman and Steinfatt, 1993; Belgrave et al., 1994; Pahlavan and Rafiqul, 1995). These studies emphasized the importance of aquathermolysis as a source of H2S during steam and hot water injection. This process may be quite efficient for temperatures higher than 200°C at production time scale. Moreover, H2S yields and formation rates appeared to depend merely upon the amount and the nature of organic sulfur compounds in heavy oil (Hyne et al., 1984; Attar et al., 1984; Lamoureux-Var and Lorant, 2005). This latter observation suggests that, as a first approximation, the H2S potential of a reservoir rock submitted to steam injection might be correlated to the content of the most hydrothermally labile sulfur compounds in the reservoir. Assuming these compounds might be contained in specific fractions of the oil sand, the aim of this work was:
1/ to assess which fraction(s) of the oil sand (SARA + insoluble) might be the source(s) of H2S;
2/ from this assessment, to correlate H2S generation to sulfur distribution over the source fractions, via a kinetic formulation.
The phase behavior of Athabasca vacuum bottoms (ABVB), a 798.15+ K (525+ oC) boiling fraction comprising 32 wt. % pentane asphaltenes, + pentane mixtures is elucidated using x-ray transmission tomography. These pseudo binary mixtures are models for the development of novel heavy oil/bitumen production and refining processes. Depending on the overall composition, these mixtures are shown to exhibit three and four phase equilibria including both expected (L1L2V) and unexpected (L2L3V) phase behavior separated by a small L1L2L3V zone. These multiphase equilibria provide challenges in production environments, where miscible flooding is typically desired, but afford new opportunities for the development of separation technologies in refining. Example pressure-temperature at constant composition phase diagrams and pressure-composition at constant temperature phase diagrams, which focus on the bubble pressure region where multiphase regions arise, are presented. Limited phase equilibria data sets for ABVB + heptane, decane and dodecane are also presented so that trends for ABVB + alkane mixtures with the size of the alkane diluent can be explored. We expect these phase diagrams to provide insights to heavy oil producers and refiners in addition to providing a benchmark for testing phase behaviour models for these and related complex hydrocarbon mixtures.
Rising oil price and demand has led to increased effort to develop reservoirs in the North Sea that were previously considered uneconomical by major operators. The recent DTI ‘Promote' licensing initiative has encouraged smaller oil companies to apply for exploration/appraisal acreage on a limited financial commitment basis for two years before initiating a more traditional work program.
Companies using this option to develop heavy oil reservoirs in the North Sea, many of which were discovered in the 70's, face a number of uncertainties traditionally associated with heavy oil. These include the determination of density and live oil viscosity at reservoir temperature where no clear correlation exists and the determination of reservoir properties from a limited range of historical data. In the offshore environment heavy oil developments are further complicated by the high front-end costs, limited reservoir size and uncertainty in geology and productivity. Only four of the heavy oil fields discoveries on the UK Continental Shelf (UKCS) have reached development and we review these fields to illustrate the challenges.
Many of the reservoir and fluid uncertainties can be addressed with modern logging and analysis methods and recommendations for data gathering campaigns in these environments are provided.The technological challenges of an offshore heavy oil development can be met with advances in sand control, ESP technology and EOR techniques. Combined together these solutions provide more accurate production forecasts, which help the economics of developing the resource to be better understood.
The proposed appraisal and development of a heavy oil field situated in Block 9/3b is used as a case study to highlight the challenges faced by operators in the development of heavy oil fields in the North Sea. Re-evaluation of historical data was used to develop a range of production forecasts that fully capture the potential and risk of the development.
This paper describes a method of sand consolidation and channel repairing by using a Resin system, the system comprises of a resin (a mixture of elastomers UF, MF and a suitable plasticizer) and a hardener (a mixture of two mild Lewis Acids). The hardener controls curing time. The role of plasticizer is to impart flexibility and impact resistance to otherwise brittle natured UF-MF resin. Surface bonding between Sand and resin has been enhanced with a special additive, if required.
This paper also describes a methodology of placing a chemical casing during or after drilling a caving prone shale zone, strong enough to prevent sloughing of shale and withstands mechanical shocks during drilling, which would facilitate drilling with reduced mud weight and without reduction of hole size.
Experimental results on resin development and mechanical parameters of sand consolidation and Chemical casing of different mineralogy have been presented. The compressive strength of the consolidated sand and shale is found to be extremely high to withstand the overburden pressure and mechanical impacts during drilling. The designed application methodology is described in detail.
This system would be extremely economic as it can be applied directly after perforation if required, saving rig time and reducing completion cost compared to Gravel pack, liner placement and Screens, with the added advantage of no hole size reduction and better sand consolidation as compared to other methods. The developed chemical system is 1/3 the cost of epoxy resins, reported earlier for similar application and the components are environment friendly and easy to handle because of their water solubility.
INTRODUCTION    
In sandstone reservoir one of the most common well problems faced by operators is sand production problem. Every year, well cleaning and work-over operations, related to sand production, cost the industry millions of dollars. Additional expenses associated with sand production include pump maintenance, well cleaning, disposal of dirty sands, etc and if we talk about caving shell is the most trouble making which is incidentally the cap rock for most of the sandstone oil reservoir. Due to presence of clay minerals in compacted form as the major component and particularly when the clay is of high swelling nature e.g. Montmorillonite the shale starts swelling when comes in contact with aqueous drilling fluid filtrate and when swelling pressure exceeds fluid column head pressure it detach from the matrix and falls, this phenomenon is known as ‘caving'. The caving phenomenon in drilling is highly unwanted due to its various detrimental effects such as stuck pipe, bit-balling etc. These problems seriously affect the drilling velocity and well quality, and raise the drilling cost and even loss of hole. The cost arisen from wellbore instability in shales has been estimated conservatively to be in the order of magnitude of US$500 million per year. Shales, which swell upon contacting water, are often referred to as heaving or sloughing shales. Such shales upon contact with aqueous drilling fluids swell and fracture rendering the well bore wall unstable. In such cases, the well bore wall sloughs into the well bore. Sloughing of shale and other similar unstable materials into the well bore can cause the drill string to become stuck and can enlarge the well bore resulting in large subterranean cavities. Such problems are frequently attributed to mud shale chemical interaction.
Unstable wellbores occur when formation pressures exceed the pressure exerted by the drilling fluid. Two situations can produce such a condition: (a) the wellbore fluid pressure is lower than the insitu formation pressure and (b) the insitu formation pressure increases because of water adsorption and similarly problems like water channeling is also caused due to several factors like poor cement bond, cement channeling, improper cleaning of hole prior to placement, old and aged cement often develops interconnecting fractures, caverns formed by sand production, channel in formation, natural fissures, hydraulic fractures, and frequent stimulation in the near wellbore.