Tectonic aspects of super-viscous oil deposits formation and placement within the Volga-Ural anteclise

The article discusses the tectonics and developmental features of the Volga-Ural anteclise during the Baikalian, Caledonian, Hercynian and Alpine tectogenesis cycles. In this paper, particular attention is paid to stages and directional development during the evolution of geological structures. The main factors of the formation and destruction of Permian viscous oil and natural bitumen reservoirs are presented in the provisions of oil ontogenesis. It was noted the cyclical nature of these phenomena. Keywords: Volga-Ural anteclise; super-viscous oil; tectonic; reservoir; oil.

A computational scheme for calculating the temperature field when oil production problems

The paper presents an approach to coupled modeling of hydrodynamic and thermal processes occurring in the oil reservoir during field development using thermal methods of enhanced oil recovery. To simulate the processes of non-isothermal multiphase flow, an approach based on implicit calculation of pressure using the finite element method and an explicit calculation of phase saturations is used. A computational scheme for calculating the temperature field is considered. This scheme makes it possible to take into account both heat transfer between phases and heat transfer of a fluid mixture and matrix-rock. In order to take into account the effect of thermal conductivity, a coefficient characterizing the rate of heat transfer between the fluid mixture and the rock is used. The proposed scheme also takes into account the effect of the temperature field on the phases flow in the field reservoir and provides for the possibility of heat sources and sinks occured due to chemical reactions or thermodynamic processes in gaseous phases. Numerical experiments were carried out on a model of a real oil field obtained as a result of history matching of well data. The model contains a large number of wells and is characterized by a high heterogeneity of the porous medium. The applicability of the considered computational scheme is demonstrated on the example of modeling hot water injection into wells crossing a formation with super-viscous oil. The efficiency of thermal methods for the development of super-viscous oil fields is shown. When hot water was injected into the reservoir, the increase in oil production was about 25 % due to a significant decrease in oil viscosity. The time spent for calculating the temperature field while simulating a multiphase flow did not exceed 6 % of the total computational time.

Field Realization of Adaptive Reservoir Simulation for Steam Injection Forecasting

Globally, steam injection for heavy and high-viscous oil recovery is increasing, including carbonate reservoirs. Lack of full understanding such reservoir heating and limited information about production and injection rates of individual wells require to forecast steam injection not only deterministic and simple liquid displacement characteristic modeling types, but also the data-driven one, which covers the adaptive modeling. The implementation and validation of the adaptive system is presented in this paper by one of the world's largest carbonate reservoirs with heavy and high-viscous oil of the Usinsk field. Steam injection forecasting in such reservoirs is complicated by the unstable well interactions and relatively low additional oil production. In the adaptive geological model, vertical dimensions of cells are similar to gross thicknesses of stratigraphic layers. Geological parameters of cells with drilled wells do not necessarily match actual parameters of those wells since the cells include information of neighboring wells. During the adaptive hydrodynamic modeling, a reservoir pressure is reproduced by cumulative production and injection allocation among the 3D grid cells. Steam injection forecasting is firstly based on the liquid displacement characteristics, which are later modified considering well interactions. To estimate actual oil production of steamflooding using the reservoir adaptive geological and hydrodynamic models, dimensionless interaction coefficients of injection and production wells were first calculated. Then, fuzzy logic functions were created to evaluate the base oil production of reacting wells. For most of those wells, actual oil production was 25 – 30 % higher than the base case. Oil production of steamflooding for the next three-year period was carried out by modeling two options of the reservoir further development - with and without steam injection. Generally, forecasted oil production of the option with steam injection was about 5 % higher. The forecasting effectiveness of cyclic steam stimulations of production wells was done using the cross-section method, when the test sample was divided into two groups - the best and the worst, for which the average forecasted oil rates after the stimulations were respectively higher or lower than the average actual oil rate after the stimulations for the entire sample. The difference between the average actual oil rates after the stimulations of the best and the worst groups was 32 %, i.e. this is in how much the actual oil production could have increased if only the best group of the sample had been treated.

Overcoming Downhole Fluid Sampling Challenge Using Dual-Port Straddle Packer in Shallow Viscous Reservoir

Objectives/Scope: Downhole fluid sampling of high quality, low contaminated oil samples with a pumpout wireline formation tester (PWFT) in a shallow unconsolidated reservoir with high H2S, high water salinity and filled with viscous oil is a quite challenging operation. Key properties, related to fluid flow in low pressure reservoirs: formation mechanical weakness, drilling invasion and the high contrast on fluid mobility, have resulted in the failure or impracticality of conventional methods for efficient sampling, resulting in a long sampling time causing high rig cost overhead and often highly contaminated oil samples. Most common problems faced during sampling are: Sand production- causing caving and lost seals and no pressure or samples. Sand plugging of the tool flowline. Operation limitation of pressure drawdown- dictated by extremely low formation pressure and mainly due to having saturated pressure around 20 to 30 psia below formation initial pressure (based on 118 bubble point samples measured in the laboratory). To maintain rock stability and low pressure draw down, fluids were pumped at a low rate, resulting in a long operation time, where a single sample take up to 15 – 20 hours of a pump out. Even with the long pumpout time the collected sample is often highly contaminated based on laboratory PVT analysis report. Methods, Procedures, Process Understanding of the formation properties and its rock mechanics helps to design proper operating techniques to overcome the challenge of viscous oil sampling in unconsolidated sand reservoir. A pre-job geomeechanical study of unconfined sand with very low compressive strength, restricted the flow rate to a maximum drawdown per square inch to maintain rock stability while pumping out. Dual-Port Straddle Packer (figure 1) sampling was introduced to overcome the mentioned challenges. Its large flow area (>1000 in² in 8 ½″ OH section) allowed a high total pumping rate while maintaining very low flow rate per square inch at the sand face, which resulted in an ultra-low draw-down flowing pressure to prevent sand collapse and producing below bubble point pressure that could invalidate further PVT studies. Packer inflation pressure has also been limited to a maximum of 150 to 200 psia above hydrostatic pressure to achieve isolation without overcoming the sand weak compressive strength. During the clean-out operation crude oil tend to separate from water based mud (WBM) filtrate in the packed-off interval due to fluid density difference and immiscibility of the two liquids due to the lower shear rate applied (among others). So a water/oil interface forms within the packed-off interval. As pumping continues, this oil/water fluid contact moves toward the bottom inlet port allowing more clean oil to accumulate at the top. Results, Observations, Conclusions: With the advantage of the dual inlet port straddle packer and the independent opening/closing operating design of each port, a clean segregated oil sample was collected from the top port at an early stage of job operation, saving rig time and cost without compromising collected fluids quality that is valid for PVT studies. Novel/Additive Information: Dual-port Straddle Packer with large flow area (plus filters) with ultra-low drawdown pressure to stay above bubble point pressure in shallow heavy oil reservoirs resulted to be another provided a cost effective technology that can be utilized for collecting downhole samples (DHS) that will undergo PVT studies.

Mathematical modeling of a new method of transportation of viscous petroleum products at low air temperatures

High viscosity petroleum products such as fuel oils and cracking residues are widely used as marine and boiler fuels both in Russia and in its exports. Conveying viscous petroleum products at low air temperatures has a high cost due to the unloading and cleaning processes of the transport tanks. Refined petroleum product cools and solidifies during transportation, becoming highly viscous, making it impossible to drain it without preheating to restore fluidity. Emerging difficulties are common to all countries with long winters and geographically wide areas. To justify a new method of rail transport of viscous petroleum products while maintaining their high temperature and fluidity by suppressing the natural convection of the petroleum product at the stage of filling the tanker. Temperature field calculations using the finite element method and the ANSYS R18.2 package are presented. The business process of the proposed transport method is universal for all modes of transportation. Using Petri nets and simulation modelling, it is investigated using the example of cleaning a tank car boiler from highly viscous residual oil products. You must perform these operations periodically during the operation of the tank wagon, and they are mandatory before every scheduled inspection and repair. Viscous oil products can be transported in a new way, the duration of the cleaning process of the tank wagon boiler is reduced by three times and the amount of water consumed is reduced by one and a half times.

Mitigation of False Brinelling in A Roller Bearing: A Case Study of 4 Types of Greases

Four commercial greases with various thickeners and base oils were experimentally examined to compare their false brinelling wear resistance in a test rig simulating roller bearings during rail/sea transportation for the first time. Greases containing zinc dialkyl dithiophosphates (ZDDP) showed superior false brinelling reduction, evidenced by no visible wear mark in the raceways. The mechanism for false brinelling mitigation was shown to be from a ZDDP-induced tribofilm which decreases the friction and wear coefficient in the contact area. Surface chemical analysis showed that for grease lubricated fretting contacts, ZDDP-derived tribofilms can be generated in the presence of micro-sliding motions and energy dissipation at the contact interface at low frequency (i.e. 4-8 Hz), due to the mechanochemical reactions. For greases without ZDDP, false brinelling wear was reduced by 97% when using grease with a more abundant and less viscous oil, which bleeds readily from an open structured thickener. The results highlight the ability of ZDDP as an additive in grease to better protect roller bearings against false brinelling during rail/sea transportation.

An Experimental Study of Improving Viscous Oil Recovery by Using Hybrid Enhanced Oil Recovery Techniques: A Case Study of Alaska North Slope Reservoir

Summary Shallow reservoirs on the Alaska North Slope (ANS), such as Ugnu and West Sak-Schrader Bluff, hold approximately 12 to 17 × 109 barrels of viscous oil. Because of the proximity of these reservoirs to the permafrost, feasible nonthermal enhanced oil recovery (EOR) methods are highly needed to exploit these oil resources. This study proposes three hybrid nonthermal EOR techniques, including high-salinity water (HSW) injection sequentially followed by low-salinity water (LSW) and low-salinity polymer (LSP) flooding (HSW-LSW-LSP), solvent-alternating-LSW flooding, and solvent-alternating-LSP flooding, to recover ANS viscous oils. The oil recovery performance of these hybrid EOR techniques has been evaluated by conducting coreflooding experiments. Additionally, constant composition expansion (CCE) tests, ζ potential determinations, and interfacial tension (IFT) measurements have been conducted to reveal the EOR mechanisms of the three proposed hybrid EOR techniques. Coreflooding experiments and IFT measurements have been conducted at reservoir conditions of 1,500 psi and 85°F, while CCE tests have been carried out at a reservoir temperature of 85°F. ζ potential determinations have been conducted at 14.7 psi and 77°F. The coreflooding experiment results have demonstrated that all of the three proposed hybrid EOR techniques could result in much better performance in reducing residual oil saturation than waterflooding and continuous solvent flooding in viscous oil reservoirs on ANS, implying better oil recovery potential. In particular, severe formation damage or blockage at the production end occurred when natural sand was used to prepare the sandpack column, indicating that the natural sand may have introduced some unknown constituents that may react with the injected solvent and polymer, resulting in a severe blocking issue. Our investigation on this is ongoing, and more detailed studies are being conducted in our laboratory. The CCE test results demonstrate that more solvent could be dissolved into the tested viscous oil with increasing pressure, simultaneously resulting in more oil swelling and viscosity reduction. At the desired reservoir conditions of 1,500 psi and 85°F, as much as 60 mol% of solvent could be dissolved into the ANS viscous oil, resulting in more than 31% oil swelling and 97% oil viscosity reduction. Thus, the obvious oil swelling and significant viscosity reduction resulting from solvent injection could lead to much better microscopic displacement efficiency during the solvent flooding. The ζ potential determination results illustrate that LSW resulted in more negative ζ potential than HSW on the interface between sand and water, indicating that lowering the salinity of injected brine could result in the sand surface being more water-wet, but adding polymer to the LSW could not further enhance the water wetness. The IFT measurement results show that the IFT between the tested ANS viscous oil and LSW is higher than that between the tested viscous oil and HSW, which conflicts with the commonly recognized IFT reduction effect by LSW flooding. Thus, the EOR theory of the LSW flooding in our proposed hybrid techniques may be attributed to low-salinity effects (LSEs) such as multi-ion exchange, expansion of electrical double layer, and salting-in effect, while water wetness enhancement may benefit the LSW flooding process to some extent. The LSP’s viscosity is much higher than the viscosities of LSW and solvent, so LSP injection could result in better mobility control in the tested viscous oil reservoirs, leading to improvement of macroscopic sweep efficiency. Combining these EOR theories, the proposed hybrid EOR techniques have the potential to significantly increase oil recovery in viscous oil reservoirs on ANS by maximizing the overall displacement efficiency.

Design Researches in Making In-Situ Thermal Foam System as a New Enhanced Heavy Oil Recovery Method

The paper presents the results of lab and filtration studies aimed at improving the procedure of thermal/gas/chemical effect (TGCE) with the generation of thermogenic system in reservoir conditions, proposed as an alternative to the methods of increasing oil recovery, such as water-gas effect procedure and foam injection process. The objects of research were thermal/gas generating compositions at the basis of sodium salts of sulfamic and nitric acids. Moreover, the influence of the ionic composition of the aqueous solution and temperature on the surface properties of the attracted solutions of surfactants (surfactants) was also evaluated. Filtration tests have shown that the use of a thermal/gas generating composition leads to additional displacement of high-viscous oil. The introduction of surfactants in the thermal/gas generating composition promotes foaming in the porous medium of the reservoir model and prevents gas breakthrough that leads to an increase in the oil displacement factor up to 24 %.