Production Of Heavy Crude Oils Research Articles

Optimization of ESP performance through chemical treatment using a single capillary in the Apiay field

The future of production in the Apiay field lies in the T2 formation, although it poses significant challenges, such as high fluid encrustation and heavy crude oil production. These issues have led to strong emulsion problems and operational issues with many wells' electro-submersible pumping systems (ESPs). In response, companies have decided that all wells with ESP equipment in the T2 formation should undergo downhole treatment using capillary scale inhibitors and fluidity improvers. However, due to operational and design constraints, some wells only have one capillary, making it difficult to prioritize and decide on a single treatment. Ecopetrol and ChampionX have collaborated to develop a new flow improver that can be applied with the scale inhibitor in the same capillary without causing incompatibility or affecting product performance. This innovative solution was implemented in five wells, using 600 ppm for the flow improver, and 25 ppm for the scale inhibitor, resulting in a significant increase in crude oil production by up to 79%, USD 55.000 in cost savings in capillary system installation, 29% energy savings, and reduced emissions. This successful application is innovative and unique in Colombia, and it sets an example for other fields facing similar challenges in the couuntry, offering a promising approach to leverage heavy crude oil production and transform the future of these fields.

Enrichment of microbial consortia for MEOR in crude oil phase of reservoir-produced liquid and their response to environmental disturbance.

Developing microbial consortiums is necessary for microbial enhanced oil recovery (MEOR) in heavy crude oil production. The aqueous phase of produced fluid has long been considered an ideal source of microorganisms for MEOR. However, it is recently found that rich microorganisms (including hydrocarbon-degrading bacteria) are present in the crude oil phase, which is completely different from the aqueous phase of produced fluid. So, in this study, the microbial consortia from the crude oil phase of produced fluids derived from four wells were enriched, respectively. The microbial community structure during passage was dynamically tracked, and the response of enriched consortia to successive disturbance of environmental factors was investigated. The results showed the crude oil phase had high microbial diversity, and the original microbial community structure from four wells was significantly different. After ten generations of consecutive enrichment, different genera were observed in the four enriched microbial consortia, namely, Geobacillus, Bacillus, Brevibacillus, Chelativorans, Ureibacillus, and Ornithinicoccus. In addition, two enriched consortia (eG1614 and eP30) exhibited robustness to temperature and oxygen perturbations. These results further suggested that the crude oil phase of produced fluids can serve as a potential microbial source for MEOR.

Development of a Process Control System for the Production of High-Paraffin Oil

This work is aimed at developing methods for increasing the production of heavy crude oil while optimizing energy costs. Various methods have been studied for recovering heavy oil from deep reservoirs. Based on the developed methods, a number of dynamic models have been obtained that describe the behavior of the temperature field in the tubing. Estimations of thermal deformation are carried out. On the basis of dynamic models, fundamentally new devices are obtained and registered in the prescribed manner, providing a subsystem for automated process control systems.

Screening of waterflooding, hot waterflooding and steam injection for extra heavy crude oil production from Tatarstan oilfield

Thermal enhanced oil recovery techniques, especially steam injection, are the most successful techniques for extra heavy crude oil reservoirs. Steam injection and its variations are based on the decrease in oil viscosity with increasing temperature. The main objective of this study is the development of advanced methods for the production of extra heavy crude oil in the oilfield of the Republic of Tatarstan. The filtration experiment was carried out on a bulk model of non-extracted core under reservoir conditions. The experiment involves the injection of slugs of fresh water, hot water and steam. At the stage of water injection, no oil production was observed while during steam injection recovery factor (RF) achieved 13.4 % indicating that fraction of immobile oil and non-vaporizing residual components is high and needed to be recovered by steam assisted EORs.

Flow enhancer influence on non-isothermal systems for heavy crude oil production

Production of heavy and extra-heavy crude oils generally entails high costs, especially in the winter season, due to heat losses. This work studies the effect of a flow enhancer (a chemical formulation based on biodiesel and oxidized biodiesel of soy oil) on the viscosity of heavy crude oil from different wells in Northern Mexico. The observed results indicate a non-linear decreasing behavior of viscosity concerning temperature and volume fraction of the viscosity reducer. It is also presented a theoretical model that predicts the flow increase that can be achieved using the enhancer in systems in which crude oil temperature is higher than the temperature of the environment. Results showed adequate correspondence between experimental and predicted data. It was found that the enhancer increases the volume of crude oil that can be processed without varying pressure gradient.

ANALISIS PENGGUNAAN LISTRIK ARUS SEARAH UNTUK MENINGKATKAN LAJU PRODUKSI MINYAK BUMI JENIS MINYAK BERAT

rom EEOR, Electro Enhanced Oil Recovery, and a developing technology application which has been established earlier. The difference is ESOR relatively does not improve recovery factor of producing well. Ideally any crude oil producing well will be experiencing pressure decline which may affect crude oil production decrement, naturally. Regarding some similar researches around the world, the use of direct current electrical exposure was proven to increase number of heavy crude oil production. At least salinity, hydrocarbon chemical compounds and crude oil flow in the reservoir (electro-osmosis) involves during chemical processes in the reservoir while ESOR application. Number of electrons conducted from direct current electrical power supply will be a supporting media during chemical process of these parameters. Unfortunately after completing ESOR application in Lapangan X, the result was contradictive with this research hypothesis. Exposure of direct current electrical supply did not increased heavy crude oil production. On a contrary, parameter of salinity and API gravity as produced heavy crude oil quality, were improving significantly.

The new integrated oil service contracts in a Venezuela in dire straits

Despite the high level of political risk, an increasing number of international arbitration disputes and the economic turmoil that Venezuela is going through, Petróleos de Venezuela (PDVSA) agreed with private investors a new model of integrated oil service contracts in September of 2016. The model contract attracted private service companies to develop one of the world's largest drilling projects to increase heavy crude oil production in the Orinoco Belt Basin. The projects come as a plan to stop the decline in Venezuelan oil output, which is now below 2 million barrels of oil per day, 1 million less than ten years ago, before a nationalisation wave transferred the operating control from private operators to PDVSA. Indeed, after years of operating mismanagement by the Venezuelan national oil company, which has provided financial support to the populist governments of Hugo Chavez and Nicolas Maduro, the current government recognises the need to outsource a variety of regular operating activities to private service contractors. The project represents US$3.2bn in investments, and ventures are betting for new opportunities where they can have more operating and financial control to reduce the risk of PDVSA's operating mismanagement and payment delays to service contractors. This article aims to explain how PDVSA managed to attract service contractors to work under integrated oil service contracts in a Venezuela in dire straits, providing an analysis on how oil companies can balance complex risk scenarios under appropriate legal conditions.

Preparation of phase transfer functional catalysts and their application in viscosity reduction of heavy oils

Four kinds of nanosilica-supported metallic and metatitanic acid nanocatalysts were synthesised as potential phase transfer catalysts for enhancing heavy oil recovery via a liquid-reduction method. The catalysts were carried by water and transferred into oil phase, and the catalytic performance of catalysts for the aquathermolysis reaction and viscosity reduction of the extra-heavy oil recovered at Shengli Oilfield (Dongying, China) was investigated. At a mass fraction of 1%, an aquathermolysis reaction temperature of 150°C and an aquathermolysis time of 36 h, the as-synthesised silica/zero valence iron and nickel (denoted as SiO2/Fe/Ni) catalyst was able to reduce the apparent viscosity of the two kinds of heavy oils by 79.3 and 77.6%, showing promising application in the industrial production of heavy crude oil.

Homogeneous and Stratified Liquid-Liquid Flow Effect of a Viscosity Reducer: I. Comparison in parallel plates for heavy crude

Production of heavy crude oil in Mexico, and worldwide, is increasing which has led to the application of different methods to reduce viscosity or to enhance transport through stratified flow to continue using the existing infrastructures. In this context, injecting a viscosity improver that does not mix completely with the crude, establishes a liquid-liquid stratified flow. On the basis of a parallel plates model, comparing the increase of flow that occurs in the one-phase case which assumes a complete mixture between the crude and the viscosity improver against another stratified liquid-liquid (no mixing between the oil and compared improver); it was found that in both cases there is a flow increase for the same pressure drop with a maximum for the case in which the flow improver is between the plates and the crude.

Transportation of heavy oils using polymer-stabilized oil-in-water emulsions

The increase in demand for crude oil and the depletion of light crude oil reserves have led to increase in the production of heavy crude oils. This has resulted in an interest in decreasing the pumping costs by techniques such as heating, dilution and/or mixing with water. Among the aforementioned methods, emulsification of heavy crude oil with water is the cheapest, and hence, optimizing its application has found increasing attention. This study uses one of the heavy crude oils in Oman to study the viscosity reduction achieved by emulsification with water at different oil fractions, temperatures, shear rates and salt content. Two chemicals were used to stabilize the emulsions, namely a nonionic surfactant and an anionic, high molecular weight polymer. It was found that viscosity reduction higher than 90% can be obtained through the creation of oil-in-water emulsions with oil content of less than 70%. Generally, it was found that there is no effect on the viscosity reduction obtainable from oil-in-water emulsions produced using the nonionic surfactant at shear rate up to 1620 s−1, temperature up to 80 °C and salt content up to 2.0 wt%. On the other hand, the viscosity reduction using water-in-oil emulsions at a temperature of 30 °C increases with surfactant concentration and shear rate. Also, the increase in salt content adversely affected the viscosity reduction obtained using water-in-oil emulsions. Moreover, it was possible to create oil-in-water emulsions with 60% oil content and viscosity reduction of around 100% in tap water using 100 and 1000 ppm polymer at all temperatures investigated. However, the use of 2.0 wt% salt resulted in lowering the viscosity reduction to 53 and 80% at 30 and 45 °C, respectively. This diverse effect of salt was almost neutralized at 60 and 80 °C resulting in viscosity reduction higher than 90%. The emulsions created using 3 wt% surfactant were generally stable for one week to a temperature of around 23 °C. The stability of oil-in-water emulsions with an oil content higher than 60% was not affected by the presence of salt. The emulsions prepared with an oil content of 60% in 100 ppm polymer were stable only for 1 h. However, the stability in water for these emulsions was greatly enhanced by increasing the viscosity of the continuous water phase by using 1000 ppm polymer, which resulted in stability higher than 70% after 24 h of incubation at 23 °C. The presence of 2.0 wt% salt in 1000 ppm polymer emulsions resulted in rendering these emulsions as instable even after 1 h of incubation. It can be concluded that high molecular weight polymers can find application in drag reduction for heavy crude oils after thoroughly investigating the effect of different polymer molecular parameters such as molecular weight and charge density.

Preparation of zirconia‐doped titania superacid and its application in viscosity reduction of heavy oil

Sulphated titania superacid (denoted as SO4 2−/TiO2) and sulphated zirconia-doped titania superacid (denoted as SO4 2−/ZrO2/TiO2) were prepared via a liquid-phase in-situ method. As-prepared SO4 2−/TiO2 and SO4 2−/ZrO2/TiO2 superacids were characterised by transmission electron microscopy, field emission scanning electron microscopy, X-ray diffraction and Fourier transform infrared spectrometry. Moreover, the catalytic performance of SO4 2−/TiO2 and SO4 2−/ZrO2/TiO2 for the aquathermolysis reaction and viscosity reduction of the extra-heavy oil recovered at Shengli Oilfield (Dongying, China) was investigated. It was found that SO4 2−/TiO2 and SO4 2−/ZrO2/TiO2 as the catalysts for the aquathermolysis process of the tested extra-heavy oil have good catalytic performance. Saturated hydrocarbon, aromatic hydrocarbon, resin and asphalt composition of the tested heavy oil sample before and after aquathermolysis reaction indicates that the amount of the saturated hydrocarbon and aromatic hydrocarbon are increased, while the amount of resin and asphalt are decreased, showing promising potential in the industrial production of heavy crude oil.

Hydrodynamic study of multiphase flow transport of highly viscous foamy fluids

Abstract Presence of multiple phases (oil, water, gas and sand) is very common in the oil industry, especially in the production of heavy crude oils. The complex behavior of this multiphase flow is aggravated by the significantly high viscosity of the oil at surface conditions. This phenomenon is frequently found in most Venezuelan heavy oil fields, which water is transported emulsified in oil with a gas fraction carried out as disperse bubbles into the liquid emulsion which is known as foamy oil, and other part of gas is a separate continuous phase generating different flow patterns in pipelines. Some efforts have been done in the hydrodynamics study of this type of multiphase flow mixtures. In order to understand how these systems behave, experimental data have been acquired for two-phase gas/oil and three-phase gas/oil/water mixtures flowing through horizontal pipes of 0.0243 m and 0.0508 m diameters, with 8.5 wt% of water and 1.5 wt% of a surfactant, pressures up to 255 kPa, temperature around 20 °C, superficial gas velocities between 0.92 and 17.56 m/s and superficial liquid velocities between 0.04 and 1.07 m/s, and oil viscosity of 0.43 Pa.s at the operational conditions. Three different flow patterns were obtained for the operational conditions: foamy slug flow, foamy stratified flow and foamy annular flow. Different models to predict flow pattern transitions were evaluated. It was found that the stratified – non stratified model of Brito et al. has good agreement with the experimental data used. For the slug-annular transition, the Taitel and Dukler model and the Barnea model tend to overestimate this transition while Brito et al. can be applied in both two-phase gas/oil and three-phase gas/oil/water systems for highly viscous liquids with the best match.

Preparation of silica‐supported nanoFe/Ni alloy and its application in viscosity reduction of heavy oil

Nanozero valent iron and nickel particles of silica composite (SiO2/Fe/Ni) were prepared via sodium borohydride reduction of ferric chloride and nickel chloride mixed solution in the presence of surface-modified silica. The prepared nano-SiO2/Fe/Ni was characterised by transmission electron microscopy, X-ray diffraction, Fourier transform infrared spectrometry and Brunauer–Emmett–Teller specific surface area method. It was found that the SiO2/Fe/Ni, composed of silica with an average size of about 12 nm and zero valent iron and nickel nanoparticles (Fe/Ni) with an average size of several nanometres, exhibited good anti-oxidation stability, dispersity and phase transfer function. The catalytic effect of SiO2/Fe/Ni on the Shengli extra-heavy oil was evaluated at a low temperature and the sulphur content of heavy oil before and after aquathermolysis was analysed by an elemental analyser. Results have revealed that the SiO2/Fe/Ni has good catalytic performance in the aquathermolysis process of heavy oils. In particular, at the condition of mass fraction of 0.5% and reaction temperature of 150°C for 48 h, it could significantly reduce the viscosity of heavy oil from 184 to 42 Pa·s. When compared with the original heavy oil sample the viscosity reduction rate was 77.17%, showing promising potential in the industrial production of heavy crude oils.

Biological Treatment of Wastewater from the Exploitation of Heavy Oil

Biological treatment of heavy crude oil production wastewater is well-established method for remediation of these wastes. We have developed effective biological treatments by (1) utilizing microbes with high oil-degrading abilities, (2) allowing greater organic loads while increasing both process stability and the resistance to shock loading, (3) minimizing the production of waste sludge byproducts, and (4) adopting anaerobic and aerobic biological processes to improve the biodegradation of the wastewater. Fixed-film bioreactors with 15h hydraulic retention times have decreased chemical oxygen demand by 74.8%, total suspended solids by 90.9%, oil by 80.6%, and phenols and sulfides by 100%. The results with anin situpilot system show that the bioreactor's hydrolytic acidulation and contact oxidation tanks are suitable for treating oilfield wastewater, and that water quality after treatment fully meets national drainage standards.

Using Biological Treatment of Henan Oilfield -Produced Water: Pilot Plant Test Study

Biological treatment of heavy crude oil production wastewater is well-established method for remediation of these wastes. We have developed effective biological treatments by (1) utilizing microbes with high oil-degrading abilities, (2) allowing greater organic loads while increasing both process stability and the resistance to shock loading, (3) minimizing the production of waste sludge byproducts, and (4) adopting anaerobic and aerobic biological processes to improve the biodegradation of the wastewater. Fixed-film bioreactors with 15h hydraulic retention times have decreased chemical oxygen demand by 74.8%, total suspended solids by 90.9%, oil by 80.6%, and phenols and sulfides by 100%. The results with an in situ pilot system show that the bioreactor's hydrolytic acidulation and contact oxidation tanks are suitable for treating oilfield wastewater, and that water quality after treatment fully meets national drainage standards.

Changes Associated with Field-Scale Demonstration in a Steam-Stimulated Crude Oil from the Lagunillas Oilfield (Lake Maracaibo, Venezuela)

Cyclic steam injection with alkali is currently very commonly used to improve heavy-crude oil production in Venezuela. This work is an analysis of oil-associated water and crude samples from LL-2670 well in the Lagunillas oilfield at Lake Maracaibo (northwestern Venezuela). The aim of this research is to analyze the organic acids thus generated and evaluate chemistry changes in the saturated and aromatic fractions of crude oil during the first cycle of steam stimulation by cyclic injection with alkali. It was noted that the percentages of sulfur and saturates, aromatics, resins, and asphaltenes (SARA) and the American Petroleum Institute (API) gravity varied little in the analyzed crude. In contrast, there were significant variations in the biomarker distribution, particularly in the mono- and triaromatic steranes, benzothiophenes, phenanthrenes, and alkyl-naphthalenes of the crude.

Extra Heavy Crude Oil Downhole Upgrading Using Hydrogen Donors Under Cyclic Steam Injection Conditions: Physical and Numerical Simulation Studies

Summary Physical simulation experiments of a downhole upgrading process showed that the use of a hydrogen donor additive (tetralin) in the presence of methane (natural gas) and mineral formation under cyclic steam injection conditions led to an increase of at least three degrees in API gravity of treated extra heavy crude oil, a three-fold viscosity reduction and an approximate 8% decrease in the asphaltene content with respect to the original crude. A continuous bench scale plant was used at different temperatures (280 – 315 ºC) and residence times (24 – 64 h) for carrying out kinetic studies. A reaction model involving four pseudo-components (light, medium, heavy and asphaltene fractions) was used and the kinetic parameters (pre-exponential factors and activation energies) were determined. Using these data, compositional-thermal numerical simulations were carried out and validated using the bench scale data. The results showed a good match between the calculated and experimental ºAPI gravities of the upgraded crude oil (average relative error 4%). Using the previous model, the downhole upgrading process was numerically simulated under cyclic steam injection conditions. The simulation runs showed the production of 12 ºAPI upgraded crude oil, accumulated over a 70-day cycle. However, a reduction in the percentage of conversion of tetralin was observed (0.8%) in comparison with the bench scale experiments (3%), which was attributed to gravitational segregation of the steam coupled with low mixing efficiency of the hydrogen donor with the extra heavy crude oil at reservoir conditions. Introduction Underground upgrading processes have always been of interest to the petroleum industry, mainly because of the intrinsic advantages compared with aboveground counterparts. Lower lifting and transportation costs from the underground to refining centres can be achieved, as well as a potential increase in the volumetric production of wells. In addition, a decrease in the consumption of costly light and medium petroleum oils used as solvents for heavy and extra heavy crude oil production can also be obtained. Finally, the use of porous media (mineral formation) as a natural chemical 'catalytic reactor' will allow the improvement of the properties of the upgraded crude oil, further reducing expenses for downstream refining operations. Several methods of underground crude oil upgrading have been reported. These concepts include downhole steam distillation(1), deasphalting(2–5), underground visbreaking(6–9), hydrogen(10–17) or hydrogen precursor injection(18–22) and in situ combustion(23–25). With the exception of the latter, the numerical simulation of downhole upgrading processes has relatively little research on it. Shu and Hartman(8) and Shu and Venkatesan(26) used compositional simulation and experimentally measured kinetic data to determine the effect of the visbreaking reactions on the percentages of recovery of heavy crude oil produced by cyclic steam injection and steamflood. For the former route, the authors found an increase of 5% in the oil recovery due to viscosity reduction in the heated zones of the reservoir(8). Similarly, Kaskale and Farouq Ali(7) reported the numerical simulation of a steamflood in a five-spot array for the production of upgraded Saskatchewan crude oil.

Comparison between refinery processes for heavy oil upgrading: a future fuel demand

Petroleum refining industry is entering into the significant era of reformation due to the depletion of light petroleum and an increase in heavy or extra heavy crude oil production. There is a strong need to revise the processes that are commercially available for heavy crude oil refining. Upgrading of heavy and extra heavy oil by means of catalytic processes requires new generation catalyst along with several modifications of process conditions. This review focuses on the description of different ways to convert heavy crude oils into synthetic crude oil. Specific illustrative examples of hydroprocessing indicated how such studies may open up new routes in the search of suitable catalyst and process for upgrading heavy petroleum. [Received: October 10, 2007; Accepted: January 12, 2008]

Production of Heavy Crude Oil: Topside Experiences on Grane

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper OTC 18240, "Production of Heavy Crude Oil - Topside Experiences on Grane," by S. Husoy and S. Hatlem, Norsk Hydro A/S, prepared for the 2006 Offshore Technology Conference, Houston, 1–4 May. Grane field production started in September 2003. Oil is exported to the onshore terminal at Sture in a 28-in. 212-km-long pipeline. Gas for injection is imported in an 18-in. 50-km-long pipeline from the Heimdal field center. Grane is the first oil field on the Norwegian continental shelf producing heavy crude. Close cooperation between Norsk Hydro's operations department, project-development team, contractors, and partners forms the basis for completing the Grane facilities on schedule, below budget, and without any serious incidents. Introduction Grane is the tenth field put into production by Norsk Hydro and is the first heavy-crude-oil (19°API) field on the Norwegian Continental Shelf. The full-length paper presents some of the challenges and experiences that Norsk Hydro as an operator has faced during field development and the production ramp-up period. Most of the challenges were well known beforehand, and the facility and organization were prepared accordingly. However, some of these challenges were underestimated. The production facility, including the organization, has been able to use the flexibility present to adjust directly or prepare temporary solutions while permanent solutions were developed and implemented. Environmental Focus The platform was designed to meet the zero-discharge philosophy of the operator. A disposal well was drilled as part of the predrilling campaign. This well was completed with 13 3/8-in. casing to an Oligocene sand reservoir 500 m true vertical depth above the oil reservoir. A drill-cutting slurrification unit in the drilling module grinds all drill cuttings and creates a seawater-based slurry. This slurry is injected into the disposal well. A disposal well for produced water was drilled as the first platform-drilled well and delivers produced water to the same formation as the drill cuttings. No produced water is discharged to the sea under normal operation. Water treatment includes degassing and hydrocyclones. Grane is allowed to direct 10% of yearly produced water to sea; however, the water-injection system uptime was more than 95% in 2005. The energy requirement for heating the oil is met by use of a waste-heat recovery unit that recovers energy from the exhaust of the turbines. This energy is transferred into the separation process by use of compact heaters. Heat transfer also is achieved from produced water before injection and from the crude before it enters the export pumps. The wellstream has a 70°C temperature entering the first-stage separator. Because sufficient separation of the crude is not achieved at this low temperature, heat is supplied upstream of the second-stage separator where inlet temperature is increased to 90 to 110°C.

Feasibility to apply the steam assited gravity drainage (SAGD) technique in the country's heavy crude-oil fields

The Steam Assisted Gravity Drainage (SAGD) processes are one of the most efficient and profitable technologies for the production of heavy crude oils and oil sands. These processes involve the drilling of a couple of parallel horizontal wells, separated by a vertical distance and located near the oilfield base. The upper well is used to continuously inject steam into the zone of interest, while the lower well collects all resulting fluids (Oil, condensate and formation water) and takes them to the surface (Butler, 1994) (Figure 1). This technology has been successfully implemented in countries such as Canada, Venezuela and United States, reaching Recovery Factors in excess of 50%. This article provides an overview of the technique's operation mechanism and the process' most relevant characteristics, as well as the various categories this technology is divided into, including all its advantages and limitations. Furthermore, the article sets the oilfield's minimal conditions under which the SAGD process is efficient, which conditions, as integrated to a series of mathematical models, allow to make forecasts on production, thermal efficiency (OSR) and oil to be recovered, as long as it is feasible (from a technical point of view) to apply this technique to a defined oil field. The information and concepts compiled during this research prompted the development of Software which may be used as an information, analysis and interpretation tool to predict and quantify this technology's performance. Based on the article, preliminary studies were started for the country's heavy crude-oil fields, identifying which provide the minimum conditions for the successful development of a pilot project.