The pdf file of this paper is in Russian. To purchase the paper in English, order SPE-138064-MS.
This article describes the method of integrated application of horizontal well test result and log data interpretation for refining the simulation model of a specific field. It is stated that the filtration reservoir parameters resultant from the well test interpretation can be more accurate versus the petrophysical model results. Therefore, this method can be useful for underappraised fields and greenfields that do not have robust petrophysical dependencies.
We have formulated and investigated the problem of averaging filtration reservoir parameters in the simulation model to match them with horizontal well test result interpretation. The averaging method has been validated using numerical well test models and subsequent interpretation of synthetic pressure build-up curves. The method of matching simulation model parameters and well test result interpretation can be useful for all fields where horizontal wells are used for development.
The article details the problem of horizontal well test result interpretation at a specific field and describes the uncertainty assessment.
This field is located in Eastern Siberia and is the largest oil field in the region. The main development target is terrigeneous VC reservoir. The key G&G features of the reservoir are:
• High number of permeable intervals in the section (up to 12) with net pays of up to 12 meters
• High degree of permeability heterogeneity: 100-4000 mD
• Low reservoir temperature: 10-14 degrees ?
• Gas caps.
The reservoir is developed using horizontal wells with 500 meter horizontal wellbore length. The wells are located according to the inversed seven-spot pattern. Most of the wells have open-hole completions. Well tests were carried out in 90% of the wells, including 60% of the wells, which have been re-tested.
The process of geological and simulation modeling faces the following problems:
1. Lack of robust petrophysical model
2. Hard to run production logging and identify producing intervals in horizontal wells: there is a risk of paraffin deposition and failure of flow meters, gas liberation takes place when a producing well has bottomhole pressure lower that the bubble point.
Due to this, the urgent problem is to create the geological-and-simulation model of the reservoir, refined based on numerous well test data.
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-135679-MS.
Mathematically formulating and implementing a semianalytical-layered geomechanical model by simplifying assumptions about field configuration and properties allows fast numerical estimation of production-induced displacements and stress changes in a reservoir. The developed fast semianalytical model was applied to a parametric study of hydraulic fracture reorientation in a water-flooded field in western Siberia. Results of the study indicate that for the typical conditions in the field, the perturbation of pressure induced by the injection pattern is sufficient to initiate considerable rotations of hydraulic fracture planes. The angle of rotation is very sensitive to anisotropy of initial stress; thicker pay zones result in larger swing angles. This software tool is fast, both in terms of calculation time and time required to set up a numerical task, and is very convenient for preliminary quick-look studies before constructing a detailed 3D reservoir model. The speed of the software
tool makes it applicable for parametric, optimization, or sensitivity studies, which require multiple trial simulations in a reasonable amount of time.
The pdf file of this paper is in Russian. To purchase the paper in English, order SPE-138047-MS.
In modern world the well acknowledged tool for management in industrial and environmental safety, and occupational health are the management systems conforming to ISO 14001 "Environmental Management System?? and OHSAS 18001 "Occupational Health and Safety Management Systems?? International Standards.
Amid the increasing competitive ability and global financial crisis, it is very important to be able to assess the efficiency of investments in HSE activities aimed at mitigation of Company's negative impact upon the environment and personnel. When developing such a system of economic assessment, the author has analyzed different methods applied for environmental performance assessment and has studied thoroughly the requirements of ISO 14031 "Environmental Performance Evaluation?? International Standard.
Based on mathematical and statistical methods, the author has elaborated an HSE performance evaluation system which enables to assess efficiency of HSE activities performed in the company. This evaluation system assumes differentiated approach to assessing all kinds of negative impact on the environment and the personnel of the company with application of input and output cost indicators. In compliance with ISO 14001:2004 and OHSAS 18001:2007 two kinds of impact on the environment and the personnel have been sorted out in Udmurtneft - environmental aspect and hazard to the personnel, correspondingly.
The research paper contains the detailed calculation of efficiency of financial investments in the personnel hazard management "Feral-herd infections?? in N company. This hazard is a top priority risk in the company since such infections are located in the region.
High efficiency of the personnel infection risk mitigation activities was proved on the basis of mathematical method and risk mitigation results were demonstrated by the model risk matrix.
Thus the developed HSE performance evaluation system enables to assess the effectiveness of HSE Integrated Management System on the whole and to allocate the financing wisely and implement risk management activities in the most successful way.
Objectives of the research paper:
- development of the HSE Integrated Management System efficiency evaluation system which would allow fulfilling several tasks:
- optimization of planning the activities and financing;
- providing visuality of HSE activity planning and assessment for the management team;
- improvement of HSE management system;
- providing transparency of HSE activity in the company.
The pdf file of this paper is in Russian. To purchase the paper in English, order SPE-138080-MS.
The paper describes the developed method called "modified reservoir quality map ". The paper includes the theoretical base of the method, the methodology for quality map construction and mathematical operations over the map. Definitions for well and well network qualities are presented. The work includes a description of the working principle of our developed software for mapping the quality of the reservoir. Finally, the results of applying the method for three fields with examples of wells (that are in "good" and "bad" zones) are presented.
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.
The pdf file of this paper is in Russian. To purchase the paper in English, order SPE-133746-MS.
Tight reservoirs start to play increasingly more important role in petroleum industry. However, quality of the most part of the 3D reservoir models created in Russia does not allow a trustworthy reservoir characterization and their development optimization. This circumstance is one of the causes for rather low recovery factors in the territory of the RF. To significantly improve the quality of those models production logging data is to be more widely used in reservoir simulation. Recovery enhancement activities become much more efficient when based on reliable reservoir development models.
With specific reference to simulation of one of the "Gazprom neft" tight fields, the paper shows how the integration of welltest data in 3D simulation results in more confident modeling and improves the current oil production and ultimate oil recovery. In addition, some particular features were identified in the course of the work and new approaches were developed to solve tight reservoir simulation issues.
Nowadays nonconventional wells (horizontal, multilateral, Rad Tech and others) are being extensively drilled throughout the world for the development of low-profit fields. Construction of these wells enables to reduce filtration resistivity resulting in productivity index increase and costs reduction.
To select the optimal well design with regard to reservoir characteristics, effective well operation and determination of filtration characteristics one should possess calculation methods for steady and unsteady liquid flow in reservoir. Few related papers have been published so far. However analytical methods for steady flowing are suitable for homogeneous beds with simple geometry and equal length laterals. Available approaches for description of pressure build up allow to account for various lateral trajectories but FEA or semi-analytical decisions methods are too labor-intensive for practical application.
Therefore simple methods of productivity index determination and pressure transient test interpretation are suggested for nonconventional wells. These methods are suitable for low thickness beds. The basis of these methods is the superposition of filtration resistivity for two plane problems. Trajectory of laterals is simulated as a number of closely spaced vertical wells or nodes. The suggested method allows determining the field of application and regularities for nonconventional wells.
Dimensionless fluid-movement profile calculated from steady fluid flow and a superposition method for pressure builds up in the nodes are used for determination of pressure build up. For description of build up in a node we recommend a diffusion equation in Laplace space and Stephest numerical algorithm. The problem is solved for porous and doublt porosity reservoirs.
Numerical calculations show that cross-flows occur after the horizontal or multilateral well shut-down. Pressure derivative maximum testifies to low effective length of the borehole or positive skin-effect. Knowledge of effective intervals length is critical to pressure curve interpretation.
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.
Many papers dedicated to PDC bit technology for drilling carbonate rocks describe the introduction of PDC bits in applications where roller cone bits have historically been used in order to deliver superior drilling rates. In the Orenburg region of Russia however, PDC has long been used for carbonate applications and hence a more application specific design approach was required in order to obtain a further step change in drilling performance.
Although PDC has long been used in the region, there were still frequent occurrences of erratic drilling behaviour being reported by the drilling contractors when drilling the demanding carbonate formation.
Associated with this erratic drilling behaviour was the inevitable impact related damage to the PDC cutting structure and it was indeed this exact reason which led to the application specific design approach being adopted for the 11 5/8?? carbonate section across the region.
Fig. 1 shows the location of the region between Orenburg and Buzuluk which is renowned for its harsh carbonate environment.
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.