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Abstract Oilfield scales are crystalline minerals made up of Na, K, Mg, Ca, Ba, Sr, Fe, Cl from produced water that can precipitate out in the reservoir, well, pipelines and process during the production and transportation of oil and gas. These precipitates can deposit as a result of thermodynamic and/or chemical changes and pose costly flow assurance issues to the oil industry. Several factors have been identified to be responsible including temperature, pressure, ionic strength, pH, evaporation, bicarbonate anion, super-saturation and contact time and water chemistry. Attempts to solve this problem in the past have focused mainly on the use of chemical inhibitors and the most accepted mechanism of scale inhibition is squeeze injection method. While adsorption and retention of scale inhibitors on rock formations needs more research, there had been improvement to better ways of ensuring adsorption and precipitation through nanotechnology including the use of nano-carbon enhanced squeeze treatment (NCEST). The uses of these conventional inhibitors have been found to be toxic to the flora and fauna in biotic communities during water disposal. In order to reduce the environmental burden caused by these conventional solutions and still manage the problem effectively, greener solutions have been proposed. This review x-rays the mechanisms of scale precipitation and deposition, evaluate the solutions that have been provided in literature based on efficiency, economics and environmental impact and propose guidelines to field operators in selecting optimum solutions.
Summary Integrated petrophysical models have been broadly applied in geological and petro-elastic modeling to forecast hydrocarbon accumulations and to estimate resource potential. Methodological basis of building those models have been well developed for conventional terrigenous and carbonate reservoirs; as regards the so-called "shale-type" hydrocarbon-bearing rocks, however, there are objective difficulties determined by a range of various factors that may include multi-component composition of rocks, core recovery problems, as well as process-related peculiarities of laboratory methods. This paper offers a program of special laboratory core analysis of the samples from the Bazhenov formation and an algorithm for the processing of the results with the view to build an integrated petrophysical model of an unconventional "shale-type" oil pay.
Abstract The paper presents efficient implementation of the non-equilibrium phase transitions model in compositional simulator. Reservoir non-equilibrium phase behavior effects are examined and simulated with the new approach. Compositional simulators are widely used for modeling light oil reservoirs, gas injection projects, and gas-condensate reservoirs. Some features for modeling phase transition hysteresis are implemented in black oil simulators, but not in compositional simulators. Though some non-equilibrium phase transition models for compositional simulators were reported in the literature, they were not implemented in industrial simulators because of their complexity. A new physical-based approach is presented in this paper. Modifications for this model are required only to the thermodynamic block of a simulator. All equations and matrix structures for the hydrodynamic (flow) block are not modified. The new approach is implemented as an extension block in a general purpose reservoir simulator. Implementation of the feature allows to model effects of phase transition hysteresis in compositional simulations. Criterion for determining phase transition type (equilibrium or non-equilibrium) is justified and also implemented. The application of the new option requires minimum additional input data, which is good for history matching problems. The new approach is tested with numerical cases based on real reservoir data.
Parkhonyuk, Sergey (Schlumberger) | Klyubin, Artem (Schlumberger) | Vernigora, Denis (Schlumberger) | Olennikova, Olesya (Schlumberger) | Lisitsyn, Andrey (Schlumberger) | Konchenko, Andrey (Schlumberger) | Sitdikov, Dmitry (Bashneft) | Bildanov, Vladislav (Bashneft) | Gaponov, Mikhail (Bashneft)
Abstract Development of traditional oil reservoirs is becoming increasingly challenging with time as more reservoirs move to brown state. The Bashkiria field complex is typical example of such reservoir: development started in 1932 and as of today, more than 80% of initial oil reserves have been produced. Thus, the only method to make wells produce economically is hydraulic fracturing. Particularities of the region are viscous crude oils, small net height of the reservoir, and low bottomhole static temperatures coupled with depleted reservoir pressure. This imposes additional constraints on the hydraulic fracturing design. The typical practice in region is to employ an aggressive pumping strategy to maximize fracture conductivity and minimize the amount of fluid pumped into the reservoir. Robust fluid is required to avoid premature screenout due to proppant settling. Another essential component of the fracture conductivity is fracturing fluid breakers. The goal in using breakers is to reduce fluid viscosity and break polymer residues in the proppant pack after treatment to facilitate fracture cleanup. Traditionally, breakers based on ammonium persulfate (APS) (both live and encapsulated) are used in Russian oil fields. They have proved successful in the typical conditions of Western Siberia (80 to 120°C). Enzyme-based breakers have limitations on temperature range and fluid viscosity range. In this paper, we focus on development of novel fracturing fluid tailored for Bashkiria oilfield conditions. An enzyme breaker was compared with traditional oxidative breakers. Production analyses were performed using actual treatment data and post-fracturing production data and comparing them with conventional treatment results. Laboratory testing proved that in terms of fracture-pack conductivity, the new enzyme breaker produced approximately twice the conductivity, as did oxidative breakers over the temperature range of the Bashkiria region. Implementation of novel fluid with pressure-independent viscosity behavior led to a reduction of more than twice the screenout rate with zero fluid-related screen outs. Up to 9 times production increase resulted based on a dimensionless productivity index.
Abstract The Bazhenov formation contains huge hydrocarbon reserves and covers the most of West Siberia territory. In most cases its productivity is assosiated with the presence of permeable layers ensuring natural inflow of oil. Both global and Russian experience in development of unconventional reserves has shown that the stimulation process is the key method of introducing previously inaccessible reserves into development. It should be noted that current level of multi-stage fracturing technology development does not provide the cumulative production required for payback of a drilled well. In the near future fracturing technology development should be focused on the increase of stimulated reservoir volume by creating artificial fracture network in relatively ductile source rocks. The authors believe that Bazhen wells productivity calculations should consider not only geological, but first of all technological uncertainties and risks. This work shows a shift from the deterministic 2D forecast of the well production profile to the probabilistic 3D forecast making it possible to take into consideration a significant range of technological uncertainties related to development of source rock deposits in the Bazhenov formation. Meeting the technological challenges, such as creating high density fracture network and reduction of the well cost, is the key target for projects of Bazhenov formation investigation.
Abstract For the past several years, cores and image logs have been utilized extensively by petroleum geologists to solve many exploration and development related challenges. However, maximum utilization of these data has not been achieved due to lack of availability of advanced computation techniques and methodology. Because of the limited utilization, the need for these very important logging data may be questioned, particularly in this highly cost-sensitive period of oil industry. In this study, different advanced techniques have been systematically demonstrated to display the maximum utilization of this logging data for oil exploration and development activity. Much critical information, such as rock texture, thin laminations, formation dip, and reservoir heterogeneity, cannot be clearly understood using conventional log data because of very low resolution. INPEX geologists decided to conduct a detailed analysis on existing core samples and image log data to identify and understand heterogeneous reservoir properties that will be critical information for future field development. At the beginning of the workflow, raw data from the field were carefully processed though accurate depth matching and applying the most accurate processing parameters. After initial processing of field data, different advanced techniques were applied to achieve the maximum amount of high-resolution information from these data utilizing Techlog*wellbore software platform:Log quality control Image calibration with shallow resistivity Static and dynamic image creation Fullbore image creation Slab-like image creation Dip picking Sand counting analysis Sand resistivity spectrum analysis Porosity spectrum analysis To achieve the most information from core photography data, core slab photographs were converted to digital array data through the latest technique of core array creation. First, core photographs(whole core four-direction photograph and slab photograph) were loaded into the Techlog platform, and core photos were converted to red, green, blue, and grayscale 2D arrays. *Mark of Schlumberger
Abstract Light oil fields development often demonstrates some evidence of oil-gas phase transition hysteresis. Phase transition rate depends on the process considered: changing state from dissolved in oil to free gas or reverse gas dissolution (re-solution) in oil . The difference in phase transition dynamics leads to such phenomena as continuous free gas production in reservoirs with pressure above initial bubble point. Reservoir simulators are used for forecasting reservoir dynamics and decision support. For most of the common practical problems, BlackOil model is the choice. The main object of the present study was to analyze reservoir simulators option for controlling gas re-solution and to modify the mathematical model of the option in order to account for the process dynamics known from experimental data. The existing and new versions of the gas re-solution reservoir simulator option were considered on the example of a waterflood pattern. The process studied was gas liberation during primary oil production followed by waterflooding with increasing reservoir pressure. Fluid properties were taken by data from Sherkalinskaya formation Tala zone of Krasnoleninskoye field, for which the effects of slow gas re-solution were observed. Results of the simulations with different gas re-solution options were compared by basic field development indicators. Also the contact experiment in a pVT bomb was simulated in order to demonstrate physical effects observed for different versions of the mathematical model of gas re-solution. The suggested extension of the option accounts for two major aspects of gas re-solution known from experimental data. The first one is the dependence of gas re-solution rate on the value of over pressure above the initial bubble point. The second one is the fact that re-solution is a relaxation process which has exponential time dynamics. The developed mathematical model included these two aspects and was implemented in a reservoir simulator. The results of the test runs show considerable influence of a gas re-solution option used on the dynamics of reservoir pressure, gas-oil ratio and oil production. The presented approach to gas re-solution control in reservoir simulators is based on data of experimental studies of non-equilibrium phase transitions of hydrocarbons. A flexible tool has been developed for history matching of flow models for the reservoirs with pressure increase after primary oil depressurization below bubble point. Matched model can be used to produce physically consistent forecasts of efficiency of various technologies for gas re-solution and further field development.
Abstract Hydraulic fracturing is one of the major techniques in modern well stimulation practices. The purpose of the current contribution is to gain novel insights on utilization of cold water for fracturing services in Western Siberia aiming to reduce non-productive time and price while maintaining excellent quality of service delivery. The study covers the hydration of non-modified guar gum and borate crosslinking in cold water conditions, the associated risks and plausible benefits are also considered. Among all fracturing services, conventional borate crosslinked guar gum fluids remain the most widely utilized due to their economical profitability, availability, ease of viscosifying and handling. The reduced temperature of water affects the guar swelling and hydration during linear gel preparation and influences the crosslinking reaction rate for delayed borate systems. One of the obvious drawbacks of the guar-based fracturing fluids is the necessity for a water heat-up process, especially during winter period. Within the scope of present study we are discussing the opportunities and perspectives of non-modified guar fluids for cold water fracturing applications. This original research details the comprehensive laboratory evaluation and thorough theoretical study, which presents a variety of fracturing fluids available to hydrate and crosslink in water temperatures starting from 5 degrees Celsius. It was revealed that the hydration of guar polymer (loading 3.6 kg/m3) in water varies between 82-88% at 5 degrees Celsius. The optimized borate-crosslinked fluids provide viscosity greater than 400 cP at 96 degrees Celsius. The versatility of proposed fracturing fluids was proven by exceptional viscosity recovery to 400 cP in less than one minute after high shear regime in the range of 10-50 degrees Celsius, simulating the fluid behavior in near-wellbore area at ambient temperature. The scope of work included the development of cold water implementation criteria and evaluation of possible associated risks, e.g. the additional cooling effect upon contact with proppant. The results presented in the current work pave the way for implementation of conventional borate-crosslinked guar gum fluids for cold water fracturing. Without significant price increase the proposed approach allows to decrease 30% of non-productive time and reduce heating expenses. The approach is significantly beneficial in areas exposed to cold winter conditions like Russia, Alaska or Canada.
Abstract Effective development of hard-to-recover reserves is one of the key activities of Russian oil companies. Great interest in this category of deposits is related to significant reserves. Prospective target for the development in Krasnoleninskoye field are deeply buried continental deposits of Tyumen formation which are related to the category of hard-to-recover reserves. Tyumen Formation is represented by interbedded sandstone, siltstone, shale, coal and characterized by low reservoir properties, average porosity and permeability are 12 % and 0.4 md, respectively. Despite numerous attempts to come to full-scale development of these deposits - and this has become possible only since the late 90's after the introduction of hydraulic fracturing technology, but there was no significant results. The main problem in this case is very complex geological structure, and if the problem of low permeability is solved by reservoir stimulation using hydraulic fracturing, the problem of spatial distribution prediction of the sandbodies is still actual, which in turn is a cause of low drilling success, flowrates and difficulties in effective waterflooding design. At the present an attempt solving the problem by drilling horizontal wells to enter maximum amount of sandbodies and their involvement in the development at the expense of a multistage hydraulic fracturing. This paper considers an example of the successful application of the engineering approach by integrating data from various lines of inquiry (seismic, geology and reservoir engineering, well testing) in order to forecast continental deposits of Tyumen formation and successful exploration drilling organization.
Abstract The paper covers the distinctive features of thermogas stimulation for Bazhenov formation, gives data resulted from the experimental work performed at Sredne-Nazym field of OJSC "RITEK" At present structural deterioration of reserves is in progress due to the increased share of heavy-to-recover and unconventional hydrocarbons in the total structure of the Russian raw-material base. Most of unconventional hydrocarbon resources of Russia are found in Bazhenov oil source rocks (further on referred to as BS). The urgency of BS effective development is necessitated by the fact that now the land of Russia stores nonessential quantity of actual reserves. While, nonconventional reserves are estimated at over 1 trillion tons, and a potential increase of recoverable reserves greatly exceeds local current recoverable reserves. Virtually, all non-conventional reserves are spread through the regions with developed infrastructure making it possible to cut the period for field tests and commercial application of new engineering decisions to involve into effective development the BS deposits being a form of the giant world shale hydrocarbon resources. According to foreign and local experts the potential of BS recoverable oil reserves amounts to minimum 30-40 bln. tons, and that is multiply higher than a possible increase of oil reserves owing to exploration of new Eastern Siberia and Arctic fields. To develop BS deposits the technical and technological complex to increase oil recovery based on integration of thermal and gas methods is under designing.