Production of heavy oil from Alberta's vast reserves continues to be a costly and capital intensive endeavor. To date considerable research has been focused on mining, SAGD, in-situ combustion, and vapor extraction. A new chemical dispersant technology has been introduced in the past year that reduces the apparent viscosity of the produced fluids from wells in the heavy oil fields around Lloydminster, Alberta, reducing the power required to drive the downhole progressive cavity pumps (PCPs), allowing pumping rates to increase, and increasing daily oil production by up to 300%. The primary benefit is removing the obstacle of pump speed limitation due to high oil viscosity.
CHOPS production suffers from many challenges. Principally, the cold heavy oil exhibits high viscosities, in some cases in excess of 100,000 centipoises (cPs). Over the past two decades, technological advances in downhole PCPs, rod strings, well heads, and power units have improved the ability to produce heavy oils. However, when viscosities approach or exceed 100,000 cPs these advances do not overcome the excessive drag created by the heavy oils as they travel up the production tubing. The newly developed chemistry creates a dispersion of oil in water with a much reduced overall viscosity and increased mobility. The result: more oil loading into the pump, less drag along the rod string and production tubing, lower power requirements, the ability to increase the pump RPMs and, therefore, increased oil production.
This technology was developed in Western Canada and has proven itself to be successful at increasing oil production, improving on-time, and reducing servicing on Canadian heavy oil wells produced by way of cold recovery methods. This technique could be utilized in other heavy oil fields throughout the world where production rates are limited by the issues created by extreme oil viscosities.
Among of the new inventions on thermal recovery, Fast-SAGD was introduced as the next generation of SAGD with greater amounts of bitumen and lower injected steam. However, there are still many suspicions about the successful of this technology such as the incremental bitumen recovery of Fast-SAGD is from the SAGD production well or combined with the offset well? It is very difficult to conclude that Fast-SAGD is better than conventional SAGD when numerical simulation of two processes was conducted in different well pattern as well the amount of operated well.
This paper presented a comparative evaluation between conventional SAGD and Fast-SAGD in three typical formations (McMurray, Clearwater, and Bluesky) of Alberta's Oil Sand. Three reservoir models with over one hundred numerical simulations under various operation conditions were developed to achieve the most unprejudiced comparison between two recovery processes. The simulation results proved that significantly recoverable bitumen was originally produced from offset well in Fast-SAGD system and leads to higher recovery factor. But, there is only slight increase in cumulative oil recovery when two processes were performed in same pattern with similar number of production wells. The result also indicated that the difference of 10kPa between steam injection pressure and reservoir pressure in literature is not enough for both SAGD and Fast-SAGD operations. And then, this study presented a numerical investigation for evaluating the potential applicability of Fast-SAGD recovery process under complex reservoir conditions such as shale barriers, thief zones with bottom and/or top water layers, overlying gas cap and fracture systems in Clearwater formation.
Increasing demands for world energy resources have accelerated the development of unconventional resources, especially of heavy oil reservoirs. Yet, the recovery of heavy oils remains challenging mainly due to variations in their viscosity. It is well known that chemical components of heavy oil control fluid properties, such as density, viscosity and shear modulus. Open column liquid chromatography is used to separate the Saturate, Aromatic, Resin, and Asphaltene (SARA) fractions. Although SARA fractions are a common method to report heavy oil compositions, they can have over 20 % errors. In this work we discuss potential error sources and establish a best-practice methodology to reduce the errors, which results in developing a modified SARA method (VSARA) to determine the composition of heavy oil. Experimental results show that the evaporative components of heavy oils, Volatile (V) fractions, are a major source of error in SARA fraction estimates. By tracking weight changes at every step of the SARA fractionation, errors are greatly reduced. Based on the comparison between SARA and VSARA results, VSARA fractions have a significantly lower error (within a 5% range) than SARA fractions alone. Multiple measurements for a single sample by different operators revealed that VSARA measurements are repeatable. Structural differences between the fractions have been verified using Fourier Transform Infra-Red (FTIR) spectroscopy, which shows the reliability of the proposed SARA method. We also compare our VSARA analyses with viscosity and show that viscosity of heavy oils correlates with resin and asphaltene fractions at concentrations above 25%; below 25%, it is uncorrelated. Since heavy oil composition can change with depth, viscosity can be expected to vary as well. Accurate information of changes in the VSARA fractions can be used to evaluate viscosity and viscosity heterogeneity in heavy oil reservoirs, select appropriate recovery methods, populate reservoir models with viscosity heterogeneity, and thus predict reservoir productivity more accurately.
As the world faces declining production from conventional reservoirs and an ever-increasing demand for energy, development of unconventional oil reservoir, especially of heavy oils, becomes critical in the petroleum industry. There are abundant heavy oil resources in the world. Total world oil resources are estimated to be about 9-13 trillion barrels, with the breakdown being 30% conventional oils and 70% heavy oils (Meyer, 2003).
More than one trillion barrels of heavy oil in place are located in Canada, Venezuela, and Russia and more than 100 billion barrels of heavy oil are in Alaska and California (Figure 1 from Dusseault, 2004). In Canada, heavy oil production takes up more than 50% of total oil production and is considered as a "conventional oil?? resource (Bott, 2004). The Orinoco tar sands in Venezuela are the world's richest oil deposits; with an estimated 500 billion barrels of recoverable heavy oil, ; they surpass the oil reserves in Saudi Arabia. More than 30 countries in the world have abundant heavy oil reserves. Thus, developing heavy oil resources has become a sustainable form of resource development strategy in these countries (Schenk, 1991).
Heavy oils have API gravities between 10º and 22º as defined by the US Department of Energy. Extra heavy oils are denser than water with less than 10º API gravity. In comparison, the densities of conventional light oils are between 30 to 40 ºAPI units. Density and viscosity are significantly higher in heavy oils as compared to conventional oils and can be used distinguish them from conventional oils. Conventional oil viscosities range from 0.1 cp to about 10 cp while heavy oil viscosities are above 1,000 cp and could reach up to more than 1,000,000 cp (Meyer, 2003). Heavy oils contain abundant resin and asphaltene fractions with large molecules that contribute most to the high density and viscosity.
High viscosity of heavy oils makes these reservoirs special in terms of reservoir performance, reservoir modeling, shear properties of fluids and heavy-oil saturated rocks, and seismic mapping.
Jia, Hu (Southwest Petroleum University) | Yuan, Cheng-dong (Southwest Petroleum University) | Zhang, Yuchuan (Southwest Petroleum University) | Peng, Huan (Southwest Petroleum University) | Zhong, Dong (Southwest Petroleum University) | Zhao, Jinzhou (Southwest Petroleum University)
High-Pressure Air Injection (HPAI) in light oil reservoirs has been proven to be a valuable IOR (Improved Oil Recovery) process and caused more attention worldwide. In this paper, we give an overview of the recent progress of HPAI technique, based on a review of some representative HPAI projects including completed and ongoing projects. Some most important aspects for HPAI field application are discussed in depth, including reservoir screening criterion, recognition of recovery mechanism, laboratory study, numerical simulation, gas breakthrough control, tubing corrosion consideration and safety monitoring. With the successful HPAI application in Zhong Yuan Oil Field in China, it is estimated that foam or polymer gel assisted air injection should continue to grow in the next decade as a derived technology of HPAI for application in high-temperature high-heterogeneity reservoirs. The purpose of this paper is to investigate the ranges of some key parameters, new understanding based on laboratory test and successful field application, thus to provide lessons learnt and best practices for the guideline to achieve high-performance HPAI project.
Sand production in a perforated sample is determined by the onset of a significant discrepancy between strains in two orthogonal directions. The onset is also analyzed by three different sanding models, i.e., shear failure, cohesive tensile failure, and the effective plastic strain (EPS) models, respectively. Comparing these results, we conclude that the results with the shear failure criterion provide the most conservative prediction, and the EPS can provide the closest results to the testing one, given adequate plastic yielding and sanding parameters. Comparing with the cylindrical cases (open hole), both the plastic radius and critical strains calculated for the perforated cavity (cased hole) cases are calculated. A critical equivalent plastic displacement (EPD) is proposed as only one additional parameter is required on top of those from a typical elastoplastic model and such a criterion allows us to determine the sanding onset directly, those using stress, strength or strain whereas can only be indicated or interpreted indirectly, yet difficult to measure in practices.
The Vapor Extraction (Vapex) process and its many hybrid variants have attracted a great deal of attention as potentially less energy intensive alternatives for exploiting heavy oil and bitumen resources. However, despite much work over the past two decades, uncertainty remains about the basic mechanisms, the scaling aspects and the most appropriate methods of numerically simulating these processes. This paper offers some insights into several of these outstanding questions. The questions are examined in the context of an extensive and well-documented set of Vapex experiments carried out by Maini and his colleagues over the past 10 years.
We have experimented with different methods of simulating these experiments using a physics-based reservoir simulator. Despite the high permeability (greater than 200 Darcys in all of the experiments), we find that capillary pressure plays a significant role in the drainage. The simulations suggest that most of the drainage takes place in the capillary transition zone along the edge of the vapor chamber, rather than in the single-phase zone ahead of it which has not yet been contacted by vapor.
It has been emphasized in the literature that the near-linear scaling of oil rate with height observed in the experiments is dramatically different from the square root of height dependence predicted by the original analytic model of Vapex. However, the experiments also show an increasing solvent fraction in the produced oil phase as height increases. When this "solvent mixing?? effect is separated out of the rates, the remaining height dependence is less than linear, though still greater than square root of height.
The relative roles of molecular diffusion and mechanical dispersion in Vapex have been widely discussed in the literature. Generally, mechanical dispersion is expected to play a larger role in these high permeability experiments (vis-à-vis the field), due to larger fluid velocities. We present a method of inferring the diffusion/dispersion present in the simulations, despite a hidden component of numerical dispersion caused by the numerical method itself. We find that the experiments are well matched with values of diffusion and dispersion in line with literature correlations, and that the contribution of mechanical dispersion is perhaps not as large relative to that of molecular diffusion as might be expected.
The paper also provides some thoughts on questions we believe are still unanswered, including mechanisms behind the height dependent mixing phenomenon and the scaling of the experimental results to the much greater heights and lower permeabilities characteristic of the field.
This paper proposes a new methodology using condensation model to evaluate the early-period SAGD by interpreting the temperature falloff data in injector or producer obtained from fiber optics or thermal couples after the wells are shut-in. Based on the non-condensation model proposed before, the condensation model also assumes a circular hot-zone shape since in the early stage of SAGD operation, and characterize the system as composed of a steam-zone of steam temperature, a cold-zone of reservoir temperature and a transition-zone in between as the initial temperature distribution. Besides, the condensation model incorporates the effect of steam condensation on the condensation-front. The movement of steam condensation-front is calculated to account for the steam-zone shrinkage. Sensitivity analysis over this models indicates that the sizes of steam-zone, transition-zone and the observing location directly affect the temperature behavior at observation point. Synthetic case study shows that the temperature falloffs from condensation model and from simulation are in good agreement and suggests that condensation model can be used to estimate the chamber size at the early stage of SAGD. As is known, it is important to obtain an even steam chamber distribution along the horizontal wellbore to shorten the ramp-up time so that maximized economics can be achieved. In reality, the reservoir heterogeneity, the wellbore undulation and the operation condition make the steam chamber conformance impossible. Because of the ready-to-use temperature data and the semi-analytic solution, the condensation model proposed in this paper can provide quick and reliable estimation of the steam chamber size to help the engineers to monitor and optimize the chamber development thereafter.
Previous work has been done in depleted carbonated heavy oil fields located in north of Mexico to address the problem of lack or low oil production due to high crude oil viscosity using downhole chemical treatment. In order to make these mature wells economically attractive, this previously acquired experience was combined with venturi technology, resulting in a downhole hybrid system designed as an alternative method to conventional gas lift.
This paper describes an in-depth analysis and the benefits of applying a hybrid artificial lifting system based on the principle of venturi and downhole chemical treatment for improving production in mature heavy crude oil fields. This study also presents various aspects; such as, design, calculations, working principle, and sensitivity analysis. A brief description of the individual components of the system is included as well, showing that this can be modified according to the particular conditions and constrains of a well. A variation of this hybrid system was tested in a pilot project in a shallow well with promising results.
The innovations and technical contributions of this work consist of the following. Firstly, a hybrid lift system such as the one described here is beneficial for depleted reservoirs containing heavy crude oil since it allows for both: reduction of bottom hole pressure and reduction of oil viscosity at down hole conditions. Secondly, since this hybrid system is simple, deploying it into a well using a reduced diameter pipe such as coiled tubing avoids the use of a workover rig, which is crucial form the economical point of view.
Resevoir simulations are routinely employed in the prediction of the performance of SAGD (Steam Assisted Gravity Drainage) process under different operating scenarios. They have been shown to have a significant potential to predict the future performance of SAGD operations. Due to the inherent uncertainty of petroleum reservoir data, the prediction needs to take into account the geological uncertainties associated with a particular reservoir. Usually, this is achieved by obtaining a history-matched model, conditioned to production field data. The model is then used to forecast future production profiles. Since the history match is time restricted to the previous production period, this is essentially an extrapolation problem with respect to time. Hence, such forecasts may not be very accurate. In addition, the simulation time is quite substantial for field studies with a large number of gridblocks. Therefore, forecasting workflows that reduce the number of necessary simulations while providing an accurate prediction are highly beneficial.
This paper presents a new approach for predicting production performance during SAGD process based on the results of SAGD simulations for a case with 3 well pairs. The approach utilizes the following workflow. Firstly, the field data were obtained, which consist of production outputs (particularly - cumulative Oil and cumulative SOR) for a typical time horizon of 5 years and the corresponding operating conditions. Secondly, a number of equiprobable geological realizations was generated using geostatistical methods to describe the permeability and porosity uncertainties of the reservoirs. Thirdly, direct numerical simulations of all realizations were conducted under a production operating scenario for a 10-year period. Then the data-driven proxy model is built that fits the actual field data to a linear, non-local function of the simulation data. The non-locality means that all the 10-year simulation results are considered in the match of the 5-year production data. After that the proxy is used to predict the production field data for the next five years. In this work, since the actual full 10 years of data are known, the predicted data are compared with the actual production data for the same period to evaluate the prediction quality.
This workflow is applied to a synthetic 3-Well-Pair SAGD model. It is shown that the proposed approach provides a highly reliable forecasting procedure for the reservoir considered. The difference between the predicted and actual field data lies within few percents, while the computational cost remains quite low. The use of the proposed approach in the prediction of uncertain reservoir performance under different operating scenarios during the SAGD process is also discussed.
Many authors have published effects of Non Condensable Gas (NCG) injection during steam assisted gravity drainage (SAGD) operation, on one hand it provides an insulation blanket to the steam chamber and avoids heat loss to the over burden and improves the economics of the project, but on the other hand it can stall the steam chamber growth in the middle of high pay zone, provided the reservoir has high solution gas. All the commercial simulators predict the accumulation of the gas blanket ahead of steam front. However, field operations have proved that the NCG are produced along with bitumen and water and doesn't accumulate, but simulators are unable to predict the right amount when it comes to history matching and accurate predictions. This paper is focused on numerically findings of the gas transport mechanism in the SAGD operations. Many possible mechanisms were considered and found that most of the commercial simulators lack the function of gas production due to viscous liquid drag, which contributes a lot towards gas production especially during early years of SAGD. Solubility exclusion of the two major NCG i.e. CO2 and CH4 in both water and oil phases is another reason for under-estimating the gas production. Along with the above two mechanisms, interestingly, the constraints on the production wells in the simulators also account for a great deal of NCG production. Now instead of using a fraction of GOR, simulation engineers can include the complete GOR of the Alberta bitumen reservoirs to history match and predict the correct amount of bitumen and gas production.
SAGD is a thermal recovery process used in Alberta oil sands for over a decade as commercial process for bitumen recovery. Non-condensible gases (NCG) like methane and carbon dioxide are usually produced during SAGD operations. Methane, usually found as solution gas, comes out of the solution when the reservoir is heated. However, carbon dioxide is formed chemically from bitumen and/or minerals in the reservoir. Many efforts have been made to improve the process economics via gas and solvent injection. Prediction of the accurate NCG production is of much importance, as it influences the injection and production rates, steam chamber growth and ultimately recovery factor predicted by reservoir simulators.
The objective of this work was to investigate some possible mechanisms of NCG production, with a view to modify thermal simulators for correct prediction of NCG production and bitumen production.
The effect of solution gas on simulated SAGD performance was first studied by Gittins et al in the context of history matching an early field experiment. They concluded that it was necessary to leave gas out of the match, because including it caused the predicted rate of chamber development to be too slow. It was recognized that there was some deficiency in the existing formulations' treatment of NCG transport in steam chambers.
Thimm has pointed out that methane solubility in the abundant water phase may be a significant removal mechanism that is usually left out of simulations; but as indicated below it does not seem to be sufficient to account for the full discrepancy between field and simulations.
A number of other studies[3-6] since have confirmed the general impact of gas on SAGD simulations. Yuan et al developed experimental evidence of NCG accumulation at a steam front, as predicted (at least qualitatively) by simulation.
Edmunds presented an analysis of the effect of NCG accumulations on steam front advance. It was pointed out that the density of methane is very close to that of steam at chamber conditions, making the movement of gas at the edge of a chamber very sensitive to relatively small effects.