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Europe
Abstract The long-term oil development projects in the Volga-Ural region are associated with depleted reservoirs. TATNEFT fields with 80% reserves depletion level produce 16.2 million tons of oil; fields with 70-80 % reserves depletion produce 4.4 million tons out of 25.8 million tons of total production. Profitable oil production of TATNEFT fields is challenged by highly depleted reservoirs of Romashkinskoye, Bavlinskoye, Sabanchinskoye, Novo-Elkhovskoye, Pervomayskoye, and Bonduzhskoye fields. TATNEFT has developed a suite of technological options for marginal oil field development. 1.Reservoir engineering management, efficient development of depleted fields. Based on the analysis data TATNEFT specialists have selected and approved screening criteria for up to 50 different EOR techniques. Annual incremental oil production due to water-flooding management and application of EOR techniques exceeds 11.6 mln tons, including 5.1 mln tons due to tertiary recovery (about 20% of total production) and 6.5 mln tons due to water-flooding (25%). 2.Efficient oil production technologies Chain-drive pumping systems with 3-m and 6-m stroke length have been implemented in TATNEFT assets since 2002, and by the end of 2009, their number totaled to 1113. The systems show maximum efficiency in heavy oil wells and wells with emulsion-related problems, reducing specific energy consumption by up to 60%. Dual-completion systems find wide application in the development of new targets in marginal wells. This paper presents modified dual-completion systems deployed in 533 wells. Incremental oil production due to these systems has exceeded 1 million tons. A dual-injection technology was developed in 2007, and to date dual-injection systems have been deployed in 128 injectors. The new technology yielded 170 200 tons of cumulative incremental oil production. The overall operational benefit is the reduction of specific energy consumption per 1 ton of produced oil. In 2009 it made 119 kwh/ton, which is 4.7% lower as compared to 1998.
- Europe > Russia > Volga Federal District > Tatarstan > Volga Urals Basin > Romashkinskoye Field (0.94)
- Europe > Russia > Volga Federal District > Tatarstan > Volga Urals Basin > Novo Elkhovskoye Field (0.94)
- Europe > Russia > Volga Federal District > Tatarstan > Volga Urals Basin > Bavlinskoye Field (0.94)
- Well Completion > Completion Selection and Design > Completion equipment (0.78)
- Management > Asset and Portfolio Management > Field development optimization and planning (0.72)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (0.71)
- Production and Well Operations > Artificial Lift Systems > Beam and related pumping techniques (0.48)
Abstract The oil and gas fields in the Orenburg region are some of the oldest and largest in Russia. Drilling through carbonates with low mud flow rates is common in this region along with the associated challenges that these conditions present to polycrystalline diamond compact (PDC) drilling. This paper details how these conditions and others, were addressed as part of the design process culminating in a novel bit design with appreciably higher penetration rates and associated cost savings. Having encountered a series of unusual dull conditions on PDC bits run in Orenburg, a systematic design approach was adopted in order to solve a series of specific regional issues resulting in new design features which lend themselves to other applications worldwide. The team established that the best practice for drilling a particular vertical section in this region was to use a bent motor due to experiences of uncontrolled deviation close to total depth (TD). The objective was therefore not only to take into consideration the carbonate formation and flow rate issues, but also to establish the effect of the bent housing on PDC bits in order to improve the bit condition and overall performance. Subsequent 3D CAD modeling and analytical studies enabled a common approach design solution for both bent housing and carbonate type applications. These studies, together with Computational Fluid Dynamics (CFD) analyses, enabled new innovative design features to be introduced into the bit to address hydraulics, formation and eccentric bit rotation. These new features resulted in far superior drilling performance and dull characteristics, which ultimately led to record runs being achieved in the region over a 1200m section of predominantly carbonate, inter-bedded formation. The features would also prove to be transparent to the drilling contractor should they be running a bit on a straight or bent housing motor with low or high flow rates, thus acting to enhance the existing drilling practices in the region.
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock (0.68)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.47)
- Europe > Russia > Volga Federal District > Orenburg Oblast > Volga Urals Basin > Garshinskoye Field (0.99)
- Europe > Russia > Volga Federal District > Orenburg Oblast > Volga Urals Basin > Bobrovskoye Field (0.99)
- Europe > Russia > Volga Federal District > Orenburg Oblast > Precaspian Basin > Orenburg Field (0.97)
- Well Drilling > Drilling Operations (1.00)
- Well Drilling > Drill Bits > Bit design (1.00)
Abstract Novel approach to well test design and analysis for the wells with hydraulic fractures in waterflooded reservoirs is considered. General pitfalls and misuses of single well approach when applied to such systems are shown. It is revealed that for many practically important fractured wells cases conventional methods of infinite-acting radial flow regime identification are inapplicable. New technique of radial flow identification for such wells and capturing neighbor wells impact is introduced, practical examples are considered. Approach proposed is based on the exact line-source solution in the form of integral exponent unlike the traditional method of interpretation which implies the logarithmic approximation. It is shown that for wells with highly conductive extensive fractures typical time of the beginning of logarithmic approximation can substantially exceed the actual time of the beginning of infinite-acting radial flow. In this case end of bilinear flow and beginning of radial flow can be estimated based on reservoir permeability assumptions or on comparison of the bottomhole pressure dynamics with exact line-source solution for a radial well with effective radius.
- Asia > Russia > Ural Federal District > Khanty-Mansi Autonomous Okrug (0.68)
- Europe (0.68)
- Asia > Russia > Ural Federal District > Khanty-Mansi Autonomous Okrug > West Siberian Basin > Central Basin > Priobskoye (Northern Part) Field (0.99)
- Asia > Russia > Ural Federal District > Khanty-Mansi Autonomous Okrug > West Siberian Basin > Central Basin > Mamontovskoye Field (0.99)
- Asia > Russia > Ural Federal District > Khanty-Mansi Autonomous Okrug > West Siberian Basin > Central Basin > Malo Balykskoye Field (0.99)
- Europe > Russia > Northwestern Federal District > Barents Sea > Pechora Sea > Timan-Pechora Basin > Prirazlomnoye Field (0.98)
Abstract Many oil producers in the Rocky Mountains region, USA, make use of electrical submersible pumps (ESP) to assist the lift of produced fluids. This region of the country is well known for its very harsh winters, with outside temperatures as low as โ40 ยฐF (โ40 ยฐC). ESP failures resulting in increased lifting costs due to workovers, lost oil, and logistics can be caused by many factors, including reservoir solids eroding the ESP or being trapped within the intake and pump stages, mechanical and electrical problems, and scale deposition. ESPs are particularly sensitive to calcium carbonate scale formation due to the extreme skin temperatures that can develop and often require continuous chemical injection to control this problem. Calcium carbonate scale formation in ESPs is a well known contributor to ESP failures. Large pressure drops combined with high temperatures increase the risk of calcium carbonate deposition even in mildly scaling systems. Scale formation on the motor housing acts as insulation, preventing heat transfer from the motor to the well fluids, causing the motor to be insufficiently cooled. Any scale deposition on the pump impellers can cause an imbalance and vibration, degrading pump performance. Continuous scale inhibitor treatment of ESPs to mitigate calcium carbonate scaling is a common practice. However, the choice of scale inhibitor requires careful consideration due to the high skin temperatures that can develop and can lead to inhibitor decomposition. Effective continuous treatment of ESPs during the winter months in regions where very low temperatures can be expected require product formulations capable of withstanding these harsh conditions without significant changes to their physical properties. This paper presents and discusses, with the aid of laboratory and field data, the development and deployment of a thermally stable scale inhibitor suitable for treatment of ESPs that can also be deployed in very cold climates, along with the monitoring tools used to ensure effective treatment.
- North America > United States > Texas (0.29)
- Europe > United Kingdom > Scotland (0.28)
- North America > Canada > British Columbia (0.25)
- North America > Canada > Alberta (0.25)
- Water & Waste Management > Water Management > Constituents > Salts/Sulphates/Scales (1.00)
- Materials > Chemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Europe > United Kingdom > North Sea > North Sea Basin (0.99)
- Europe > Norway > North Sea > North Sea Basin (0.99)
- Europe > Netherlands > North Sea > North Sea Basin (0.99)
- Europe > Denmark > North Sea > North Sea Basin (0.99)
Abstract During the last several years Shell and its affiliates have initiated a significant number of Enhanced Oil Recovery projects covering chemical, thermal and miscible flooding applications in a variety of geological and hydrocarbon settings. Key in de-risking and sanctioning these projects is a far more detailed understanding of the fundamentals in rock and fluids physics and chemistry that have an overriding impact on the ultimate recovery and project economics. This required a significant upgrade of the experimental capability to measure relevant rock and fluid properties as well as the ability to visualize and model the EOR processes at various geological and time scales. State of the art experimental facilities have been built to enhance visualisation and understanding of flow processes in cores as well as to measure accurate physical and chemical properties. The proprietary reservoir simulator and modelling toolkit has been upgraded to include the relevant EOR processes and rock / fluid interactions in sufficient detail, covering for example In-Situ Combustion, Polymer floods, Designer Waterโข flooding, Alkaline Surfactant Polymer flooding, Thermally Assisted-Gas-Oil-Gravity-Drainage, In-Situ Upgrading, a variety of Solvents and Hybrid applications at various scales, ranging from core scale to full field simulations. The Smart Fields concept pursues continuous optimisation of hydrocarbon assets, 24 hours a day, and 7 days a week. This optimisation covers locating and recovering hydrocarbons, improving performance of production (well) facilities throughout the field life cycle on timescales ranging from seconds to field life. An important part of the Smart Fields concept is Closed Loop Reservoir Management (CLRM), which ensures that data gathered in the operations phase is used to improve quality of reservoir models and allow a faster field management cycle. Novel robust mathematical optimisation algorithms and control methods are rapidly maturing to assist automatic history matching, high-grading geological reservoir model ensembles and reducing the uncertainties. The desired outcome is better well offtake or injection policies that are also robust against remaining key uncertainties. Extending the Smart Field concepts to EOR requires the definition of the appropriate levels of smartness for EOR projects for each element of the Smart Field Life Cycle, which consists of: data acquisition, modelling, integrated decision making and operational field management, each with a high level of integration and automation. In order to optimise the performance of operational EOR projects, new surveillance methods and technologies were developed and deployed, and continue to be developed, in collaboration with oil and gas industry service providers to obtain better and cheaper data targetting improved sweep efficiency and operational cost reductions. Examples include the use of various geophysical methods to measure (steam) flood performance, the development of high temperature internal control valves to improve steam injection conformance, down-hole fiber optic applications and advanced tracer tests. Apart from pursuing improvements in ultimate recovery, improved energy efficiency and a reduced CO2 footprint have become important drivers as well and a number of recent advances have been made that will lead to both further improvements in UTC and the environmental footprint. Dissemination of knowledge, workflows, and experience across the various projects has resulted in a global EOR approach that shortens the duration of screening, feasibility and development efforts and reduces the need for field trials or pilots, reducing the cycle time for EOR projects. A number of recent examples containing elements of Smart EOR principles as described above will be provided.
- Geology > Petroleum Play Type > Unconventional Play > Heavy Oil Play (0.47)
- Geology > Geological Subdiscipline (0.47)
- North America > Canada > British Columbia > Peace River Field (0.99)
- North America > United States > Arkansas > Smart Field (0.98)
- North America > United States > Texas > Permian Basin > Brooks Field > Canyon K Formation (0.93)
- (4 more...)
Thermal Modeling for Characterization of Near Wellbore Zone and Zonal Allocation
Ramazanov, A.Sh.. Sh. (Bashkir State University;) | Valiullin, R. A. (Bashkir State University;) | Sadretdinov, A. A. (Bashkir State University;) | Shako, V. V. (Schlumberger Moscow Research, SPE;) | Pimenov, V. P. (Schlumberger Moscow Research, SPE;) | Fedorov, V. N. (Surgutneftegas) | Belov, K. V. (Surgutneftegas)
Abstract This paper describes a new method based on the analysis of non-steady state wellbore temperature distributions impacted by geothermal temperature profile, Joule-Thomson and adiabatic effects in reservoir flow to describe near wellbore parameters such as permeability distribution and to estimate flow rate distribution between producing layers. The solution of the inverse problem with respect to parameters of near wellbore zone is based on the quantitative analysis of the transient baro-thermal effects resulting from the single-phase fluid flow from the reservoir into the wellbore. In the steady state case the reservoir thermal effect is the same as the throttling (Joule-Thomson) one. It is reduced to the adiabatic effect while the fluid is stagnant. In the general case for non-steady state flow the change of reservoir fluid temperature is a combination of frictional heating and cooling resulting from the expansion of the fluid. Non-isothermal well testing (NIT) relies on the analysis of these fluid temperature changes. The method discussed in this paper allows evaluating parameters of near wellbore region (permeability and radius of damaged zone) and could be complimentary to the conventional well testing practices for a single-layer reservoir and to estimate flow rate distribution among the pay zones in a multi-layer case (zonal allocation). The paper develops mathematical models and presents the results of numerical simulation for transient processes after the start of the production phase and during well test operations including multi-rate testing. Limited to the particular cases of unsteady processes after specific wellbore operations (changes of production regimes and shut-ins), the transient analytical solutions assume that the fluid may be considered incompressible and that no conductive heat transfer occurs. In order to take into account compressibility and thermal conductivity, detailed numerical modeling has been performed. The paper compares the numerical results to experimental data and shows that the fluid heat capacity in wellbore perforated zone must be considered for appropriate interpretation of initial bottomhole temperature change versus time, in particular for small rates. Based on the analysis of the simulation results, an inverse model solution for the estimation of the near wellbore zone parameters from reservoir fluid temperature and wellbore pressure transients is proposed. The method comprises first-order estimation from analytical solution and their further numerical refinements by non-linear regression for the system "reservoir-wellbore". Example of interpretation of non-isothermal well testing field data is presented demonstrating the usefulness of this new methodology.
- North America > United States (0.46)
- Europe > Russia (0.46)
- Asia > Russia (0.28)
Abstract This paper aims to show all the steps involved in a rigorous uncertainty analysis study, completed in 2008, in static and dynamic modeling as well as try to highlight some very key steps for a successful study. Yuzhno Khylchuyu (YK) field is a Permian aged Carbonate reservoir in Timan Pechora basin in European part of Russia. It was discovered in 1981 and has since been appraised by 24 wells. The field is being developed on a regularized waterflood 5-spot pattern with 120-acre well spacing. The productive reservoir is composed of three main zones, A, B, and C. These zones are not in communication based on geo-chemical data and dynamic well test results. Zone A, which is dominantly progradational has good continuity and best reservoir properties containing 90% of the original oil in place (OOIP). Dominantly aggraditional zones B and C are discontinuous, and have poor reservoir properties. The motivation behind a rigorous uncertainty analysis on OOIP and Expected Ultimate Recovery (EUR) was due to the large capital investment required for full field development. Thus, the objective of this study was to quantify the range of uncertainty of OOIP and EUR, to identify the most influential parameters contributing to uncertainties in OOIP and EUR, and quantify the impact of those most influential parameters. Such rigorous uncertainty analysis would thus help mitigate the risks with the investment.
- Europe > Russia > Northwestern Federal District > Nenets Autonomous Okrug (1.00)
- Europe > Russia > Northwestern Federal District > Komi Republic (1.00)
- Europe > Russia > Northwestern Federal District > Northwestern Federal District > Nenets Autonomous Okrug > Timan-Pechora Basin (0.99)
- Europe > Russia > Northwestern Federal District > Komi Republic > Nenets Autonomous Okrug > Timan-Pechora Basin (0.99)
Abstract The goal of any petroleum producing country is to maximise the long-term social value of the hydrocarbon assets. To protect society's interests in development and operation of oil and gas fields, the Norwegian authorities have established frameworks for these activities, which are intended to ensure that the companies makes decisions that are also beneficial to the society at large. In Norway the Norwegian Petroleum Directorate (NPD) has the authority to monitor the development of the different oil and gas fields and to ensure that the fields are being produced in accordance with best practice reflected in regulations and the framework established. As for use of associated gas the regulation pertaining to proper utilization of the petroleum resources has been of paramount importance. In the regulations it is stated that flaring of petroleum is not allowed, unless in quantities needed for safe operation. From day one the oil companies thus had to find a proper way of utilizing the associated gas. In most cases the gas was transported in pipelines and sold to the market, but in some cases there was no pipeline available and re-injection into the reservoir was the only option. Improved recovery has been and still is of great concern for Norwegian authorities. Several initiatives have been made to evaluate the possibilities for improving oil recovery. The results of gas injection have been studied together with other methods for enhancing the oil recovery. For the Norwegian oil fields pressure maintenance by use of associated gas has proved to be very successful. By the end of 2009 and since the oil production started on the Norwegian Continental Shelf in 1971 a total of more than 3526 million Sm of oil and 2138 billion Sm of gas has been produced. Most of the gas produced has been exported to the European market. Some gas has been used as fuel on the platforms and for transportation purposes and a small amount has been used in Norway as feed-stock for petrochemical plants. Due to strict regulations and economical incentives just a minor part has been flared. However it is reported that gas in the order of 595 billion Sm has been re-injected into the reservoirs to sustain pressure and to enhance oil recovery. The average oil recovery factor for fields in production today is estimated to be 46%. It has been estimated that re-injection of gas so far has yielded an extra oil recovery of between 240 and 270 million Sm oil and condensate compared to the case without gas injection. If existing plans for further gas injection are executed, the total gains are in the range 320 to 360 extra million Sm oil and condensate.
- Europe > Norway > North Sea > Northern North Sea (1.00)
- Europe > Norway > North Sea > Central North Sea (0.93)
- Europe > United Kingdom > North Sea (0.69)
- North America > United States > Texas (0.69)
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > Europe Government > Norway Government (0.75)
- Europe > Norway > Norwegian Sea > Halten Terrace > Block 6507/11 > ร sgard Field > ร re Formation (0.99)
- Europe > Norway > Norwegian Sea > Halten Terrace > Block 6507/11 > ร sgard Field > Tofte Formation (0.99)
- Europe > Norway > Norwegian Sea > Halten Terrace > Block 6507/11 > ร sgard Field > Tilje Formation (0.99)
- (111 more...)
Abstract During last decades the air injection or the in situ combustion has found a wide application as a heavy oil IOR process in the world. The idea of the in-situ coal gasification process was initially suggested by Academician D.I. Mendeleev in 1888. In the 1930s Soviet scientists A.B. Sheinman and K.K. Dubrovai performed first attempts to initiate in-situ oxidation of oil in one of the Krasnodar region heavy oil fields. In the USSR successful heavy oil in-situ combustion (ISC) applications have been implemented at the Pavlova Gora field in Krasnodar and at Shodnitza field in Ukraine in the sixties. A review of the ISC heavy oil field application experience in the USSR will be given in this paper. The Republic of Tatarstan has the largest in the Russian Federation resources of natural bitumen, ranging from 4 to 7 billion tons. Today the air injection process is conducted by the operator "Tatneft" on two field projects at Ashalchinskoye and Mordovo-Karmalskoye (MK) fields. Natural bitumen has been produced at MK field since 1978. In this paper we will present results of our simulation study of the MK's ISC project. The simulation model of the pilot area including combustion and pyrolysis reactions, oxidation parameters was calibrated using available experimental data to match the production history of the field. The advanced dynamic gridding numerical solutions were used for modeling and history matching of the ISC process. Dynamic gridding allows achieving the accurate modeling and material balance calculations of the complex physical and chemical processes taking place at the combustion and displacement fronts in the reservoir under air injection. It allows the saving computer time required for the process modeling. Automatic history matching routines were used to properly calibrate matching parameters and to adjust the reservoir and the reaction characteristics of the simulation model. The established simulation model can be used as a tool for the ISC process monitoring at the field. The model allows also to interpret and to evaluate the pilot results, to optimize its application and to predict the IOR potential.
- Europe > Russia > Volga Federal District > Tatarstan (1.00)
- Europe > Russia > Southern Federal District > Krasnodar Krai > Krasnodar (0.45)
- Europe > Russia > Volga Federal District > Tatarstan > Volga Urals Basin > Mordovo Karmalskoye Field (0.99)
- Europe > Russia > Southern Federal District > Krasnodar Krai > Pavlova Gora Field (0.99)
- Europe > Norway > North Sea > Central North Sea > Central Graben > PL 018 > Block 2/4 > Greater Ekofisk Field > Ekofisk Field > Tor Formation (0.99)
- Europe > Norway > North Sea > Central North Sea > Central Graben > PL 018 > Block 2/4 > Greater Ekofisk Field > Ekofisk Field > Ekofisk Formation (0.99)
Abstract Passive Inflow Control Devices (PICD) has become a frequently used completion method for horizontal and close- to-horizontal wells over the past decade. There are several types of PICDs, but the working principle is similar for all of them: PICD restricts a flow by creating an additional pressure drop and therefore equalizing the wellbore pressure drop to accomplish a uniformly distributed flow along the horizontal well. To evaluate performance and potential benefits of a PICD completion, a full-field simulation model is required. Simple near-wellbore simulators are often used to initially evaluate the applicability of the PICD-based completion. However, only full-field reservoir simulation can provide prediction for the completion/reservoir performance and thus allow for a full evaluation of the economics and feasibility of the project. A multi-segment well model can be used to represent the PICDs in the horizontal well. The multi-segment well model is an advanced well modeling that allows accurate modeling of multi-phase flow and pressure variations in wells with a reservoir simulation model. This paper provides an example of the reservoir development study. PICD completion is designed and optimized to achieve the best possible economic results using in a commercial black oil simulator. The work is based both on a generic model. The methodology of implementing external pressure drop models is presented. Also, the process of optimization of the PICD-based horizontal well completions utilizing simulation is shown.
- Europe (0.68)
- North America (0.47)
- Europe > Norway > North Sea > Northern North Sea > North Viking Graben > PL 054 > Block 31/6 > Troll Field > Sognefjord Formation (0.99)
- Europe > Norway > North Sea > Northern North Sea > North Viking Graben > PL 054 > Block 31/6 > Troll Field > Heather Formation (0.99)
- Europe > Norway > North Sea > Northern North Sea > North Viking Graben > PL 054 > Block 31/6 > Troll Field > Fensfjord Formation (0.99)
- (9 more...)