Application of gas as oil displacement agent is constrained not only due to the paucity of gas resources, but due to high cost of site buildup, adverse effect of gas breakthrough on producing well behavior, and as consequence, relatively poor efficiency of the process.
Alternate gas and water injection used in mid- and high-permeability pools would enhance the process properties. At the same time, according to laboratory investigations , oil recovery factor would grow in proportion to reduction ratio of water and gas slugs. Simultaneous injection of water and gas as liquid-gas mixture (LGM) would not only improve oil displacement, but would enable to essentially enhance economic efficiency of project through significant saving of site buildup CAPEX, and reduction of OPEX.
Laboratory tests of oil displacement by means of liquid-gas mixtures were initially carried out by F.Liskevich . The tests involved simultaneous feed of gas and water through two pipes onto the face of a core sample with permeability varying from 0.003 to 0.035µm2 assuming that the porous medium filtration will turn the both components into a homogeneous water-gas mixture. A significant factor for the practical implementation of the tests results proved determination of relationship between oil recovery factor growth and water-gas mixture gas content. Maximum growth of oil recovery factor was obtained from water-flooded samples with 20-30% high gas content in the mixture under reservoir conditions.
Field water-gas mixture injection tests were carried out at the Federovski  and Sovetski fields .
In the first instance, the mixture was generated at an injection well head with the help of special-purpose device out of gas cap gas having upstream pressure of 12.0-13.0 MPa, and lake water. The Sovetski field WGM was obtained with the use of a tubing-suspended ejector run into the well out of associated petroleum gas recovered from annular space of adjacent oil wells with a pressure of 0.8-1.0 MPa and bottom water of formation pressure maintenance system.
The obtained results confirmed possibility in principle of the mixture continuous injection into mid- and high-permeability formation, and cyclic injection of the mixture into mid-permeability formations (80-100 mD).
Geophysical investigations (INNK) at the Fedorovski field wells revealed homogenous structure of the flow over the whole well bore, and within the perforation interval as well. It was found that injection of the mixture has not reduced injectivity index of the injection wells in terms of water, but, following the mixture injection, the index has experienced increase.
In the both projects, continuous duty was significantly affected by formation of hydrates in the well, while mixture injection at Sovetski field was also accompanied by sharp decline of water-intake capacity of the wells.
Results of such activities, and water-gas effect at Samotlor field, as well as available gas-lift infrastructure gave an impetus and provided a base for the development of FDWGM-aided oil sweeping technology.
Basic idea of the devised process consisted in the assumption that the water-gas mixture with highly dispersed gas phase is capable of preventing formation of hydrates in the well bore, and of ensuring a more even saturation of the formation with gas throughout its thickness.
The pdf file of this paper is in Russian. To purchase the paper in English, order SPE-136316-MS.
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 Sm3 of oil and 2138 billion Sm3 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.
The pdf file of this paper is in Russian. To purchase the paper in English, order SPE-136235-MS.
The proposed report presents an analysis of the effectiveness of enhanced oil recovery (EOR), performed on the fields Western Siberian region in the period from 2002 to 2009. Analysis reached more than 1000 injection wells and processed about 5000 producing wells.
According to the analysis of the effectiveness of EOR determining geological parameters are partition factor and directional permeability of the reservoir, it is shown that the increase in efficiency with increasing partition factor is due to increased duration of effect.
It is noted that the decrease in the effectiveness of EOR occurs with increasing development of oil reserves. It is shown that the effectiveness of the EOR is the highest in the base water cutting wells about 80%. It was found that a decisive influence on the effectiveness of EOR provides value target intensity water cutting of well production, which expresses the anticipation of the current average water cutting of well production from the current development of initially recoverable oil
reserves, shows the degree of backwardness of waterflooding processes from the processes of water cutting of well production.
The analysis showed the benefits of integrated technology EOR, different injection gel-forming and stimulation chemical compositions. The advantages are the increase in injectability of injection wells with decreasing water cutting of well production. In order to optimize the flow of reagents for each field revealed the dependence of the efficiency of EOR from specific volume of the margin, whereby determine the optimum value of this parameter.
To confirm these results, we have conducted work on mathematical modeling of the EOR, which agree well with practically the results.
The practical value of the executed analysis of fishing activities is considerably improved the accuracy of selection of technologies EOR as a direct composition of chemical reagents, and the volume pumped into injection wells tracks.
Based on the analysis it was concluded that work on the runway injection wells on the fields of Western Siberia have led to increased oil recovery;
This work has significantly clarified the criteria for effective use of technology EOR; To a large extent optimized specific volumes of injected chemical compositions.
Foremost among the issues arising from the application of chemical technologies of enhanced oil recovery (EOR), is the question of optimal choice of objects. The criteria for the effectiveness of such technologies EOR are presented in [1, 2, 3, 4], but not adequately justified. In particular, questions remain as to the applicability of chemical technologies EOR on the hard to recover reserves (HRR) deposits.
The pdf file of this paper is in Russian. To purchase the paper in English, order SPE-136335-MS.
Oil production is influenced by many parameters, for example the distribution of the petrophysical properties, fluid contacts, relative permeabilities, faults, aquifer strength etc. These parameters influence the production production process in different manners, with every parameter displaying its own, unique, level of uncertainty. This is one reason why the probabilistic approach, which takes into account the major uncertaintiesin the reservoir description and production processes, has developed into an important tool for the prediction of a field's hydrocarbon recovery. This is especially important in the case of heterogeneous reservoirs and horizontal wells. Here, unexpected early water or gas breakthrough into one of the zones will reduce the oil production by preventing oil inflow from other parts of the well.
Intelligent Well (IW) Technology has ability to identify and control the inflow rate at a zone level, preventing the breakthrough of unwanted gas or water. Previous work examined the impact of choking by an IW's Interval Control Valves (ICVs) on the geological uncertainty attributed to the statistical distribution of the formation's properties.
This paper extends this study to the "dynamic?? parameters (fluid contacts, relative permeabilities, aquifer strength and zonal skin). Each of these parameters exhibit its own uncertainty; with each, individual uncertainty being combined to generate an accurate estimation of overall risk associated with the reservoir's development. The workflow employed will be demonstrated for two cases. This will be followed by an analysis to identify which of the above factors allow the flow control ability of an IW to reduce the production uncertainty in general as well as in specific cases.
The results emphasize the importance of the probabilistic approach for production prediction and illustrate its use as a tool to justify the installation of IW Technology in a particular well. This method will be used for both estimating, as well as reducing, the risks associated with the initial uncertainty of a planned development.
Horizontal wells have become quite popular in oil industry. They can deliver an increased oil production while reducing the field development time and costs by reducing the required number of wells. This is especially relevant for offshore fields where the incremental cost per well is high. But long horizontal wells also cause production management problems, e.g. reservoirs are not homogeneous, allowing water or gas to breakthrough into different parts of the well at different times. These unwanted fluids with a higher mobility reduce the inflow from the oil bearing zones. The result is a non-uniform displacement of the oil, a reduced sweep efficiency and an increased cost due to water and gas recycling. All these factors will increase the field's operating cost and reduce its recovery and profitability.
Intelligent (or smart) well completion can help to solve these problems. IWs are equipped with downhole sensors; allowing monitoring of the inflow from the various well zones. Moreover, advanced control equipment may be used for managing the inflow into each zone. This combination of monitoring and control can give a significant improvement in the oil recovery while reducing the field's processing cost. There are two main types of flow control completions: "passive?? Inflow Control
Devices (ICDs) and "active?? ICVs.
One of the basic objects of exploration works and hydrocarbon extraction in Krasnodar territory in recent decades are Chokrak depositions in the northern edge of West Kuban Trough. About twenty light oil and gas condensate deposits were discovered there. In the 90's and 2000's the major scope of seismic studies and drilling activities were concentrated in this direction.
Most of the fields discovered are related to tectonic (disjunctive) faults and deformational traps. Genetically disjunctive tectonics is represented by listric faults having their roots in middle-upper Maikop and their flattening in Sarmatian-Meotic stratum. Faults have great influence both on deposit formation, and on the process of hydrocarbon extraction. It is necessary to understand and forecast fluid penetrating ability of disjunctive dislocations in order to create and improve geological models both during exploration works, and in the course of field development. The estimation of breakdown pressure value sufficient for tectonic disturbance fracturing can be also used during drilling of wells with a view of reducing risks of drilling mud loss and loss of circulation.
Productive sandstone units of Chokrak formation of Temryuk syncline fold in West Kuban Trough are represented by terrigenous depositions of the subsea detrital fans (Fig. 1). They are characterized by lenticular structure. Thickness of sandstone units is between first several metres to the first several tens of meters (typically 4-8m), and for clay seals it is the first tens of meters. By their zones reservoirs are limited to slope (northern edge) and distal (axial part of West Kuban Trough) detrital (alluvial) fans (cones).
The distinctive feature of Chokrak fields is their abnomarly high pore pressure and reservoir pressure (anomaly ratio is up to 2), intensive tectonic desturbances (Fig. 2) and various extent of filling for traps and reservoir units/sequences (often incomplete filling). Fluid saturation differences between sand units and neighboring tectonic blocks, as well as elastic (volumetric) drive, which is unlikely for development in tectonic sealed pools, result in situations, when it is necessary to improve the hydrodynamic model of fields that is to find out the sources of watering and formation energy. Inter-bed overflows across faults can represent one of such sources. If we define fluid permeability of tectonic disturbances it is possible to determine a source of formation energy and water, to make more precise calculation of reserves in the fields being developed and more reliable saturation forecasts for adjacent tectonic blocks, reducing thereby further exploration risks. That is why FSA (Fault-Seal Analysis) was applied.
Fault Seal Analysis has appeared at the intersection of several oil and gas disciplines - geology, geophysics and reservoir engineering. 3D survey data and their interpretation results are used in this analysis as well as well logs, core structure and texture data, and the data obtained in the course of drilling and production.
The final analysis of the results obtained through FSA application allows to establish the tectonic faults penetration ability dependency of the across-fault pressure difference and the bed shaliness factor, i.e. the extreme values of these parameters, at which sealing property of faults is changed to fluid conductive property.
Using the data and dependencies obtained in the course of work it is possible to forecast fluid permeability of faults, both at the initial stage, and in the course of development, i.e. after pressure drop inside reservoirs and increased potential of pressure between the deposits being developed and reservoirs with initial pressure.
FSA method consists of five stages. The first two stages are baseline ones since they are mandatorily performed in the course of geological exploration. Stages 3 to 5 represent the core of this method.
It should be noted that the introduced order of stages in tectonic faults permeability studies, 3 to 5, is not strict. It often happens that each subsequent stage of works forces to return to the previous stage for more precise definition, or sometimes to the total revision of previously obtained results. Thus, the whole process of studies represents an iteration cycle.
Baryshnikov, Andrey (Gazpromneft-Khantos) | Sidorenko, Vladimir V. (Gazprom Neft) | Tychinski, A. (Gazprom Neft) | Timokhovich, Y. (Gazprom Neft) | Safronov, Dmitriy Anatolievich (Gazpromneft-Hantos OOO) | Gladkov, Andrey Valerevich (Modeling Technologies Center) | Kondakov, Danila Evgenevich (Modeling Technologies Center)
The concept of "Intelligent Field?? is becoming a promising strategy in the oil and gas industry. This approach includes several levels (components) of information management:
1. Data gathering system (data channels, data transmitters);
2. Data processing and analysis (simulation and monitoring tools);
3. Data integration solutions;
4. Feedback (well response, ESP frequency response).
This paper describes the application of the data gathering and integration process supported by the data processing and simulation tools in the Southern License
Territory (SLT) of Priobskoye Field (West Siberia). The proposed solutions provide a suitable base for daily monitoring of problematic elements with the
appropriate feedback to the related services if a problem occurs.
These solutions were implemented to monitor the production process in the SLT of Priobskoye field, they were successfully used to reach the main goals:
1. Gathering of the field information in real time;
2. Introduction of the tool to control artificial lift production for our technologists;
3. Access to the information about problematic wells at least once per day;
4. Visual and analytical reports related to problematic wells;
5. Field development planning and monitoring tools for specialists involved in waterflood simulation and management.
The results of this work can be used to analyze the learning process, to evaluate the prospects of "return on investments?? put into the simulation models, which in our case are constantly upgraded and used in work. The important result of this project is a transparent and fast decision-making process supporting oil production activities.
The Southern License Territory (SLT) of Priobskoye Field is a unique filed from the viewpoint of its reserves potential (according to the Russian classification of the reserves, the recoverable B+C1 reserves as of January 1 2010 are equal to 305 MT), and it has a complicated geological structure with non-anticlinal lithologically and disjunctively screened traps, characterized by low reservoir properties, highly heterogeneous. As a result, these reserves are classified as "hard-to-recover?? reserves.
The SLT of Priobskoye Field has been developed through a large well stock, which according to the Field Development Plan consists of more than 8000 wells (all producers are fracture stimulated). There are up to three geological formations in different areas of the field, which are developed as one production target in a single well pattern. The injectors are equipped with dual injection systems, the producers have separate production string assemblies to provide individual production from each formation as required by the Reservoir Management Plan.
Bu-Khamseen, Raid Habeeb (LUKSar Energy) | Khakimov, Ayrat (LUKSar Energy) | Sierra, Leopoldo (Halliburton Co.) | Machala, Mark Stephen (Halliburton Energy Services Group) | Young, Dustin A. (Halliburton)
The pdf file of this paper is in Russian. To purchase the paper in English, order SPE-136038-MS.
Lukoil Saudi Arabia started a tight gas exploration campaign in the Rub Al-Khali Empty Quarter in 2006 and nine wildcat exploration wells have been drilled and evaluated. These prospective tight gas discoveries in the Empty Quarter have occurred in High Pressure and High Temperature (HPHT) horizons at depths between 12,000 and 20,000 feet, where the stress and temperature are extremely high in addition to micro-Darcy levels of reservoir permeability. This has made the exploration activity more challenging.
To overcome the extreme challenges and to help assure the success of the exploration activity, a new drilling, completion, and fracturing strategy was implemented in one of the most recent wells. The synergy of the new strategy steps resulted in the first successful discovery in the Sarah formation.
This paper presents the open hole compartmentalized completion steps, as well as the selective fracture stimulation strategy and challenges that have lead to the first successful tight gas discovery in the Sarah formation.
Natural gas demand in Saudi Arabia has increased substantially over the last few years. Saudi Aramco and certain international exploration companies have developed aggressive exploration campaigns in more challenging environments as compared to the existing exploited, associated and non-associated gas producing reservoirs. The exploration strategy is more challenging because the reservoir targets are low or ultra low permeability (lower than 0.01 md), reservoir pressure ranges from low to extremely high, i.e. 11,000 to 13,000 psi, with temperature conditions greater than 315oF, and reservoir porosities from poor to moderate (3%-15%) and with natural fractures.
As a part of its exploration campaign, LUKOIL Saudi Arabia, is drilling and completing wells in the empty quarter of the Rub' Al Khali area where the Qasim and Sarah formations are being completed and fracture stimulated due to its prospective potential.
During the conventional drilling process of these wells good fluorescence and/or some gas shows in the Sarah and Qasim formations are typically observed. However, after the wells are completed, perforated and fractured no gas or marginal gas production has resulted in the abandonment of these horizons.
These HPHT tight gas wells are normally drilled and completed as a cased hole with 4 ½?? liners. Liners are cemented to assure completion and wellbore integrity during the evaluation and stimulation phases. Due to the low permeability the drawdown at downhole conditions is very high. In several cases the liner and cementing process was not able to assure completion and wellbore integrity. Liner collapse at the perforations or above them resulted in the inconclusive evaluation of a candidate well and abandonment
Kremenetsky, M. (Gubkin State University of Oil and Gas) | Ipatov, Andrey (Gubkin State University of Oil and Gas) | Gorodnov, A. (Gubkin State University of Oil and Gas) | Chernoglazov, V. (Gubkin State University of Oil and Gas)
The pdf file of this paper is in Russian. To purchase the paper in English, order SPE-138049-MS.
Commingling differentiated control providing is actual problem for multi-layer oil fields in the Russian Federation. There are multiple economic benefits of commingling reserves that can provide very large increases in incremental project NPV for all types of oil and gas field developments. The benefits of commingling production from separate reservoirs are:
• ability to produce hydrocarbon from multiple reservoirs which may not be economic to produce on their own
• fewer wells, less infrastructure - lower capital expense
• lower operating expenses
• less environmental impact, fewer locations
• a sustained production plateau
The regulations for the commingling of down-hole production are typically set by government agencies responsible for oil and gas developments. There are very few areas of the world that permit commingled flow from different reservoir intervals without approved means of control, testing of segregation, and flow estimation and allocation.
Russian government regulators limit commingling by continuous monitoring stringent requirement for each reservoir. This opportunity allows a license holder to both manage and control of oil field development and water oil displacement processes.
Separate monitoring and development management task has been technically solved nowadays at pilot level by a number of national oil companies. For instance, GazProm Neft specialists tested the technical side of the problem and its possible solutions at the Yuzhno-Priobskoe oil field in 2009. The work has been continuing in 2010. .
Comingled production well monitoring
The analysis focuses on the division way theoretical aspects of reservoir parameters that dynamically changing under production:
- Skin-factor, the total (s, stot)
- Half-length of fracturing (Lfr)
- Reservoir pressure (P),
- Productivity (Q / (?P),
- Phase permeability (kphase)
- Other operating and petrophysical parameters.
It is possible to develop quantitative separate evaluation methodology for filtration and operating properties of commingling under existing monitoring systems conditions(both split operation and without it), if such calculation algorithm reliability criteria have been evaluated. Numerical modeling is needed in order to evaluate the reliability criteria estimations. The simulation modeling problem formulation and its basic solutions are presented below- in section 1.2..
Time simultaneous measurement results for each reservoir at its top level are input for comprehensive interpretation to the moment:
- Pressure (P)
- Temperature (T)
- Rate (Q)
- Water content (W).
The pdf file of this paper is in Russian. To purchase the paper in English, order SPE-138056-MS.
This report was chosen for the presentation by the Programme Committee SPE for the information examination results , included into the summary. The Society of engineers and oilworkwers didn't examine the content of the report, so it's open for alterations and corrections suggested by the authors. The Society of engineers and oilworkers, its' officials or participants do not necesseraly share ideas of the following report. Reports presented at the SPE conferences are to be examined by editorial committee of the Society of engineers and oilworkers. Copying, leasing or keeping any part of the given report for commercial profit without written permission given by the Society of engineers and oilworkers is prohibited. Prinning the summary of the report of 300 words is allowed; copying the illustrations is prohibited. Summary is to have the reference to where and when the original report was presented. Write Librarian, SPE, P.O. Box 833836, Richardson, TX 75083-3836 U.S.A., fax 01-972-952-9435.
For many years Hydraulic Formation Fracturing (HFF) was regarded as the method of involving into development new deposits or the method of intensification for wells fitted definite strict criteria of water-cut and risks. Lately the positive results of applying HFF at deposits that have been worked out long are achieved. In this work the results of HFF usage (in different design variations) at the latest stage of mining are represented , the formation BC10, of Mamontovskoe, Ust-Balykskoe and Yuzhno-Surgtskoe fields are taken as an example.
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 Water™ 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.