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-138059-MS.
Temperature transient analysis of oil and gas fields in Russia has long history. The paper is dedicated to application of temperature transient analysis for monitoring ESP wells. Currently several technologies of monitoring ESP wells are used on practice:
-analysis of residual temperature distributions in wellbore after pumping equipment is pulled-out
-measurement along the wellbore in the formation intervals during moving of cable equipment, lowered by pump
-logging through tubing above the pump
-measurements with permanently installed sensors below ESP..
The analytical and numerical models of temperature transient analysis in the wellbore taking into account convective heat transfer, heat generation in the pump and electric motor, counter flow in annular space and thermo-hydrodynamic effects in reservoir are described. In particular the possibility of gas-liquid contact and oil-water contact determination in annular space based on temperature logging through tubing is shown. Obtained results are of the interest as for production monitoring as well as for the control and management of pump-lifting equipment operations.
This paper presents the case studies of temperature logging conducted in ESP wells of oilfields of Russia.
Many "classical?? oilfields in West Siberia represent low-relief structures with long transition zones and presence of moveable water above official oil-water contacts (OWC's). Development of such "undersaturated?? accumulations is complicated by difficulties in prediction of rate potentials for new wells and risks of high initial production watercuts.
Salym Petroleum Development (SPD) company (a 50/50 JV of Shell and Sibir Energy) is successful in developing such fields in the South of West Siberian oil province. This business success is based in part on building an effective and reliable petrophysical model of reservoir rock and fluid distribution.
This was achieved through integration of core, log an production data. At the core of the algorithm is a capillary-pressure based model of transition zone interlinked with algorithms of traditional and special log evaluation as well as with models of fluid phase mobilities..
Salym Petroleun Development company has three oilfields under development (West Salym, Upper Salym and Vadelyp). The licences are located in the South of West Siberian province (figure.1).
Oil accumulations have been found in Upper Cretacious and Jurassic sands - Cherkashin AS10-11, BS8, Achimov, Bazhenov and Tyumen formations. Main reservoirs are located within AS10-11 group which are being developed through pattern waterflood in all three fields. West Salym field is the largest asset of SPD, at the moment there are more than 400 wells drilled and the field is producing around 120,000 bopd.
The pdf file of this paper is in Russian. To purchase the paper in English, order SPE-133162-MS.
Actual coning behavior in a horizontal well is not fully understood. Lacks of knowledge of fluids distribution within the reservoir and the heterogeneity as well lead to either over-predicting or under-predicting performance of the well implemented. The prediction done then needs to be revised in the effort to re-evaluate the economic of the well.
This paper presents a semi-empirical method for predicting post breakthrough performance of horizontal wells. The method was developed based on straight forward Darcy equation for linear flow and the principle of material balance. An iterative procedure of calculation is provided for predicting production performance. Based on results of the parametric study conducted using a numerical reservoir simulator, corrections necessary for the linear flow model proposed were established.
Water cresting efficiency is defined in this study by inverting the correction factor and was found systematically to relate with factors that influence the coning behavior.
The applicability of the proposed method was validated using two sets of field data. The first data set is the case having practically initial zero water cut, while the other set represents cases with high water cut since the production start up. Results of prediction for both cases are in very good agreement with the field data.
Ramazanov, Ayrat (Bashkir State University) | Valiullin, Rim Abdullovich (Geotech Inc.) | Shako, Valery (Schlumberger) | Pimenov, Vyacheslav (Surgutneftegas) | Sadretdinov, Alexandr (Surgutneftegas) | Fedorov, Vyacheslav | Belov, Kirill
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.
The first results from analysis of transient temperature changes to the tenths and hundredths degree C during fluid flow in porous medium due to the throttling effect were obtained in former USSR1. In the sixties and the seventies of last century the problem of determination of hydrodynamic parameters of oil reservoir by transient temperature behavior in the wellbore was actively studied. Today the high resolution well temperature logging is one of the informative methods in production logging. Recently, in connection with new possibilities of wellbore measurements it is observed the renewal interest to determination of near wellbore zone parameters in particular to multilayer reservoirs from transient thermal-hydrodynamic downhole (DH) parameters (pressure, temperature and rate) 2,3,4.
Urdaneta, Marisely (Petroleos de Venezuela S.A.) | Angel, Franklyn Javier (Petroleos de Venezuela S.A.) | Gonzalez Orozco, Edgar R. (PDVSA E&P) | Askoul, Yamal Eduardo (Petroleos de Venezuela S.A.) | Guevara, John Erick
A meandering system where sandbodies produced are complex, so that fluvial deltaic reservoir consist of channel belt sandbodies with highly variable permeability patterns pose a significant challenge for further development of a mature oil field in the Southwest Venezuela. To obtain an optimal strategy a multi-disciplinary reservoir characterization study was carried out.
This study combined all available data (geophysics, geology, petrophysics, and engineering) into a 3D stochastic geo-model to build a reservoir simulation model, many sensitivities with grid size and reservoir description in fluvially dominated deltaic facies were undertaken. These sensitivities included various assumptions on sand content of main producing horizons, sandbody dimensions, permeability distribution, and continuity of flood plain acting as vertical barriers in some reservoir areas.
All these sensitivities were tested during history matching as alternatives to reach a history match. Drilling locations and some exploitation strategies were made in order to improve the oil recovery factor through closing some wells for several periods (3 months - 6 months) and then opening those wells, this technique helped to decrease the water production rate and increased slightly the oil production rate. The associated economic evaluations were based on simulated forecasts while connected volume calculation was made for the chosen realization.
Reservoir G9 GF 1 was discovered in 1984. After twenty six years of production through primary recovery (water flux), it has recovered 41.4 % of its original oil in place with an increasing water cut and a considerable diminution in oil production, as a consequence of the mature stage of the reservoir. We present a case study of this reservoir which comprehends fluvial-deltaic sands with poor sand bodies connectivity, non-uniform permeability and random fluids distributions.
The purposes of this project were to conduct reservoir characterization studies up to numerical simulation and to identify opportunities to improve oil recovery through infill drilling and intermittent producing wells. In the simulation process, heterogeneities and scales were important factors for simulation blocks dimensions, as well as layering settings and upscaling of properties which can outcome with numerical dispersion effects associated to history mismatching due to some vertical thin barriers in the centre of this reservoir. Additionally, results of different simulation scenarios were analyzed in terms of production profiles and ultimate recoveries to make economical evaluations, considering increasing operating costs due to water production.
Recently, three wells have been drilled in Guafita Norte Oilfield where reservoir G9 GF 1 is located. The last part of this paper shows actual reservoir conditions (petrophysical properties and fluids distribution) compared to 3D model forecasts.
The mathematical model of two-phase displacement of oil by an acid aqueous solution in the neighborhood of a well and a hydraulic fracture is created. It takes into account the kinetics of acid dissolution of a carbonate rock. The proposed model allows us to investigate the penetration of the active admixture and the changing of the reservoir characteristics during the solution injection and after well shut-in for reaction.
The effect of well acidizing and acid fracturing are estimated. It is shown that neglecting the two-phase nature of the flow leads to the underestimation of the treatment effect. At given process parameters the needed length of the shut-in period for reaction and dimensions of the acid penetration zone are estimated.
The control of such parameters as the injection rate and the chemical reaction rate makes possible to reach the maximum treatment effect at the given solution volume. Calculations showed that in the case of the acid fracturing the significant slowing of the reaction rate may lead to large leakage of unreacted acid into the reservoir, extending the penetration zone, but also reducing the effects near the fracture and thus worsening the result of treatment.
The created model was applied to numerical calculations for real cases. Field and calculated data are in good agreement.
The pdf file of this paper is in Russian. To purchase the paper in English, order SPE-136377-MS.
To control Subsea fields in remote and challenging environments such as the artic, a large amount of system information combined with high availability are key features for a Controls system to succeed. Trying to use traditional power and communication methods, will not meet these requirements, and new ways (robust and versatile) are required.
The paper will describe how to addresses these challenges discussing high speed communication and intelligent power distribution networks. Available field history will be discussed to provide feedback.
High speed communication using fibre optic with or without local copper lines is becoming more and more the standard for subsea communication networks. The available high bandwidth feature provides the large amount of data required to control fields with complex architectures. Combining this with open communication architecture and the appropriate subsea local area network gives third parties direct access to their IP enabled devices, to monitor and actively perform data uploads. This concept is in use as a world wide first application since June 2008 on the BP Taurt Project of the coast of Egypt in the Mediterranean Sea. Further expansion of this field as well application on other projects proves the viability of this concept.
Redundant controlled power distribution (on an AC or DC basis) will provide the functionality to control power distribution to the Subsea Control Modules (SCM). This feature will allow power control to the SCMs on an individual basis. Various scenarios not possible before can now be done:
• Extension of an existing field whilst the originally installed field can remain in full operation.
• Installation and retrieval of an individual SCM without interference of the overall field by swapping the power before the Electrical Flying Lead (EFL) disconnect takes place.
This feature will also open the possibility to actively monitor the subsea voltages and currents. This information can be used to early detect any abnormal power consumption and confirm the health status of the subsea controls equipment, and provides benefits on overall system reliability/availability required in challenging operating environments such as the artic.
The pdf file of this paper is in Russian. To purchase the paper in English, order SPE-136404-MS.
Gemini surfactant flooding is a promising technique to enhance oil recovery from medium-high permeability oil reservoirs. The screening of the gemini surfactants are mainly based on their capability of lowering the surface tension between oil and water. However, gemini surfactants with high capability of lowering the surface tension do not necessarily enhance oil recovery from low permeability oil reservoirs. Based on fractal method and the mercury injection curve data, the fractal dimensions of the pore structures of low permeability oil reservoirs are different from those of medium-high permeability oil reservoirs. Based on the fractal dimensions of molecular fragments, the fractal dimensions of gemini surfactants are in relation to the fractal dimensions of the pore structures of low permeability oil reservoirs.
Based on the fractal dimensions of the pore structures of low permeability oil reservoir Z and molecular fragments, gemini surfactant D is designed and applied in developing the reservoir. Gemini surfactant D enhanced oil recovery 5% more than conventional gemini surfactants.
The fractal dimensions of the pore structures of medium-high permeability oil reservoirs range from 2 to 3. The fractal dimensions of the pore structures of low permeability oil reservoir Z are less than 2. The fractal dimension of the spacer group should match with fractal dimensions of the pore structures. The gemini surfactants are absorbed more onto the rock surface as the spacer groups of the gemini surfactants are less complicated than the rock surface.
Fractal dimension is supplementary to the parameters (permeability and porosity) that are used to estimate low permeability oil reservoirs. Low permeability oil reservoirs which were not able to be developed are able to be developed. This helps more and more low quality reserves be turned into producing reserves.
Horizontal and maximum reservoir contact (MRC) wells are intended to increase productivity and minimize water production due to water conning. Their complex geometry makes cleaning up of drilling fluids filter cake a difficult task. It is hard to distribute the acid uniformly over long horizontal sections. Poor acid distribution occurs during matrix acidizing. Coiled tubing cannot reach the total depth of the well because of some limitations such as large washouts, length of the reel and diameter of the coil, which make acidizing horizontal wells ineffective. Available chemical methods of removing filter cake like mineral acids, esters, oxidizers, chelating agents, and enzymes are limited at certain conditions.
This paper introduces a new method for filter cake cleaning using a self-destructing water-based fluid to drill long horizontal and MRC wells, which results in higher productivity. This fluid is a water-based mud that is weighted with calcium carbonate and has both functions of drilling and completion fluids, can reach total depth of MRC wells. It has the ability to effectively stimulate the whole horizontal sections after drilling. This can result in significant cost savings by elimination of acidizing using coiled tubing or any other means and improvement in filter cake removal and thus enhances performance of the treated wells.