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The 16th TH horizon is a mature oil reservoir located about 20 km east of Vienna. Screening of the reservoir and EOR technologies revealed that from one of the reservoir compartments incremental oil might be produced by gas injection.
In 2007, injection of various gases into this reservoir compartment (OOIP 86 MMstb) was investigated. An EOS model was created and slim tube experiments were performed. The results of the slim tube experiments indicated that neither CO2, CH4 or N2 are miscible with the 24.8 API oil under reservoir conditions of 120 bars and 60 degrees centigrade.
Injection of CO2, CH4 and N2 was investigated using a sector and full-field model. The results show that incremental recovery compared to the base case is only about 1.5%. Owing to the oil viscosity 5.5 cP, the gas viscosity 0.02 cP, the oil density 855 kg/m3, the CO2 density 290 kg/m3 and the reservoir thickness of 30 m, severe gas override occurs in the reservoir. The small dip of the reservoir of 2-4 degrees and high in-situ oil viscosity lead to a small gravity drainage rate, hence the incremental
recovery is limited.
At a first glance, the project could be economically attractive though. The field is located close to Vienna where some pure CO2 is emitted. The CO2 emitted could be injected to reduce greenhouse gas emissions and generate emission trading certificates.
However, in the course of the study, it was seen that significant acceleration potential exists in this horizon. Accelerating oil production leads to faster perforation of the wells upwards towards top structure. Combining gas injection with acceleration of oil production reduces the incremental oil production by this technology. The reason is early gas breakthrough in the production wells perforated at the top of the formation due to gas override.
Many of the mature oil fields in the world produce commingled water. Water production increases the lift cost of a barrel of oil, as it needs surface handling when it is to be disposed, re-injected into other wells, or used for a different purpose.
Several techniques and chemistries have evolved over the past decades to address reduction of unwanted produced water.
These different approaches to minimize water production are grouped under the name of water conformance. Selecting the proper water conformance method for a well depends on the correct understanding of the reservoir. Economics remains the main decision driver as to which technique and chemistry to use.
A quite effective technique among the different water conformance methods is conformance fracturing, a combination of hydraulic fracturing and water control. Among several operating companies, hydraulic fracturing still is the preferred technology to increase well productivity. The development of a family of lightweight proppants for hydraulic fracturing has allowed a more uniform fracture height and width, due to a lesser degree of proppant settling inside the fracture, resulting in a better connectivity with the wellbore and lower chance of breaching nearby water zones. On the other hand, chemistry of relative permeability modifiers (RPM) has been greatly improved over the past decade, and one can observe longer life on water control treatments done using RPMs.
In Brazil, we have conducted over 100 conformance fracturing operations to date, using conventional as well as lightweight proppants, and relative permeability modifiers, to meet the different targets they were deployed for.
This paper will summarize these treatments (design, logistics, materials, equipment), with obtained results (oil and water production over time), showing the improvements made over time.
Bottomhole samples were obtained from eight different wells in an undersaturated offshore oil field. A total of 25 samples were obtained from these wells at various depths. The well temperature data show considerable gradient in both the horizontal and vertical directions. Bubblepoint pressure measurements reveal unusual variations. Some of the wells have a gradual increase in bubblepoint pressure with depth. Some other wells show a decrease after increase and some wells a decrease with depth. The decrease in bubblepoint pressure with depth is the common behavior. There are also vast variations in measured composition, oil density, and the molecular weight of last fraction in different wells.
These variations can be due to compartmentalization and barriers or could be due to gravity, molecular diffusion, thermal diffusion, natural convection or reservoir filling history. Identifying the cause of the variations is important especially in offshore fields. Reservoir compartmentalization can significantly affect the field development plan and the reservoir management.
We have made an analysis of the variations in composition and bubblepoint pressure due to all the above mechanisms in the reservoir with no barriers. The results are different than the observed variations. The reservoir filling effect cannot also explain the large measured variations since calculated mixing time for the fluid is much less than the age of the reservoir. Based on our analysis we conclude existence of barriers in certain parts of the reservoir which explains significant changes in composition and bubblepoint pressure. We also show that thermal diffusion and natural convection can result in an unusual increase in bubblepoint pressure with depth.
To the best of our knowledge this is the first report of this unusual trend in bubblepoint pressure and its interpretation based on the effects of gravity, molecular diffusion, thermal diffusion, natural convection, and reservoir filling history.
Despite the numerous experimental studies, there is a lack of fundamental understanding about how the local and global heterogeneity control the efficiency of polymer flooding. In this work a series of water and polymer injection processes are performed on five-spot glass micromodels which are initially saturated with the crude oil at varying conditions of flow rate, water salinity, polymer type and concentration. Three different pore structures in combine with different layer orientations are considered for designing of five different micromodel patterns. It has been observed that the oil recovery of water flooding is increasing with the salinity concentration, for the ranges studied here. While, it shows there is an optimum value of concentration in which maximize the oil recovery in polymer flooding. The results confirmed that the highest oil recovery is obtained when the layers are perpendicular to the mean flow direction for both water and polymer flooding. Also, the oil recovery in polymer flooding increases with the increase of layer inclination angle, however it does not increase for waterflooding. In addition, the oil recovery is strongly affected by the local heterogeneity which is near injection zone. This study demonstrates the applicability of micromodel for studying of enhanced oil recovery techniques in locally and globally heterogeneous five-spot models.
Copyright 2008, Society of Petroleum Engineers This paper was prepared for presentation at the 2008 SPE Europec/EAGE Annual Conference and Exhibition held in Rome, Italy, 9-12 June 2008. This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied.
Underground gas storage operations and CO2 sequestration in aquifers relay on both proper wellbore construction and sealing function of the cap rock. The potential leakage paths are the migration along the wellbore due to poor cementation and flow through the cap rock. Although 60% of the gas storage wells undergo a costly work-over process to remedy missing cement seal only few operators consider appropriate completion solutions to minimize the risk of losses due to leaky annulus space. The leakage through the cap rock can occur by diffusion and two-phase migration. Modeling of two-phase flow requires the determination of the functional relationship between capillary pressure, relative permeability and saturation. The injected gas moves to the top of the formation below the cap rock due to gravity and density differences. Therefore, the ability of a cap rock to seal fluids is another key parameter for the successful gas storage or long term disposal of CO2 in addition to a proper completion. Capillary pressure data, which are critical for exact prediction of gas leakage through the cap rock are seldom available and yet necessary. In-situ method of gas entry pressure was developed and successfully implemented to help reducing uncertainties in gas leakage predictions. Zonal isolation of cap rock is performed followed by exchange of wellbore liquid by gas. Constant rate injection of gas is then conducted to determine the gas entry pressure into a fully water saturated cap rock. Simulations were performed using this gas threshold entry pressure to investigate the gas leakage amount through the cap rock and along the wellbore for both natural gas and CO2 storage models. It was shown that the uncertainty of predictions could be significantly reduced by using data obtained from in-situ gas threshold determination. Recommended completion solutions for both types of storage operations are presented, which minimize a risk of uncontrolled gas escape.
In the production history matching process, the reservoir simulation model is modified in a way that it becomes consistent with production data, keeping the observed restrictions of the geological characterization phase. This technique is limited, mainly in mature fields, when the production history is not reliable, or in the beginning of production, when there are only a few observed data and uncertainties are higher. The development of new saturation data acquisition tools, such as 4D seismic and
TDT/TDM logging tools helped to overcome some difficulties in the geologic model construction phase but the great challenge is how to use this data in a way to improve the petroleum production.
History matching methodologies integrated with saturation data from 4D seismic are available in literature but no publications that utilize saturation data obtained from well logging were found. The advantage of the logging tools is the data accuracy but, on the other hand, it is limited to a few feet around the wells. The main objective of this project is to integrate the traditional history matching process with logging saturation data, developing more reliable simulation models and production forecasts. The saturation data is utilized as a new parameter to be matched as well as an auxiliary tool to help to determine critical regions which will be modified. An assisted history matching methodology, utilizing saturation data, streamlines and an optimization algorithm is proposed.
The proposed methodology is applied to a synthetic reservoir model. Parameters of the process are studied and detailed, finding the best way to use the data. The model is also history matched with no saturation information and predictions of the matched models are compared, showing the benefits and restrictions of the new methodology.
Tealdi, Loris (ENI Congo) | Obondoko, Gaston (ENI Congo) | Isella, Davide (ENI Congo) | Baldini, Davide (ENI Congo) | Baioni, Antonio (ENI Congo) | Okassa, Fabrice (ENI Congo) | Pace, Giamberardino (ENI E & P) | Itoua-Konga, Felix (ENI Congo) | Rampoldi, Maurizio (ENI Congo)
Copyright 2008, Society of Petroleum Engineers This paper was prepared for presentation at the 2008 SPE Europec/EAGE Annual Conference and Exhibition held in Rome, Italy, 9-12 June 2008. This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of SPE copyright. Abstract Many West Africa Offshore Fields are maturing and operators are completing secondary targets in their wells to maintain the economic operation of their valuable assets. However, offshore environment makes the capital expenditure associated to this kind of interventions of critical importance.
We present theory and application of a new approach for assisted history matching and uncertainty assessment. In a Bayesian framework the a priori geological information is conditioned to the production history to give the posterior probability distribution function (pdf). The full posterior pdf is explored to assess the uncertainty through ensembles of reservoir models sampled by a Markov chain Monte Carlo algorithm. To achieve this we construct proxy functions for the output of the flow simulator for all measurements that enter a global objective function. The proxy functions are constructed using polynomials and multi dimensional kriging. An iterative loop, in which ensembles of reservoir models are sampled from the posterior pdf, is run to improve the quality of the proxy functions.
The power of the application is demonstrated on two reservoir models. First we apply the method on a synthetic case. A modified reservoir simulation model from a small StatoilHydro operated oil field is investigated with a synthetic production history and 20 tuning parameters. Finally we apply the method to the StatoilHydro operated Heidrun field. A model which covers the upper formations of the field with 26 production wells, 11 injector wells, and 56 tuning parameters is conditioned to 11 years of production history. We show that it is possible to construct proxy functions accurate enough to describe the full posterior pdf and thereby assess the uncertainty associated with these reservoir models.
Zainal, Suzalina (Petronas Reserach Sdn Bhd) | Manap, Arif Azhan Abdul (Petronas Reserach Sdn Bhd) | Hamid, Pauziyah Abdul (Petronas Reserach Sdn Bhd) | Othman, Mohamad (Petronas Carigali Sdn Bhd) | Chong, Mizan Bin Omar (Petronas Carigali Sdn Bhd) | Yahaya, Abdul Wafi (Petronas Carigali Sdn Bhd) | Darman, Nasir B. (PETRONAS) | Mat Sai, Rithauddin (PETRONAS)
Ensuring a pilot project a success operationally, while gathering reliable data for a full-field implementation is critical. For this reason, various aspects of project planning and operational considerations need to be addressed. This include conceptual design, facilities and operational considerations, resources planning, integration of activities and most importantly, pilot objectives. However, all these planning will not be successful without a properly designed and executed laboratory test program. Such laboratory program will minimize result uncertainty and ensure the proposed pilot meet its objectives.
The first Chemical EOR (CEOR) pilot project in Malaysia involved an Alkaline-Surfactant injection utilizing high salinity injection water in a high temperature reservoir. It pioneered the Single Well Chemical Tracer (SWCT) method for EOR project evaluation in Malaysia. The main objective of the pilot is to assess the effectiveness of the Alkaline-Surfactant formulation to improve oil ultimate recovery through the reduction of residual oil saturation.
Being the first of its kind in Malaysia, an extensive laboratory program is required to ensure the injected alkalinesurfactant formulation performed at its most optimum and conclusive data is gathered. This data will be used as input to the future field development plan.
This paper presents a comprehensive laboratory test program covering pre-pilot, pilot and post-pilot laboratory analysis designed for offshore high salinity injection water and high temperature reservoir. It highlights the challenges imposed by offshore operation to design an optimum chemical solution considering that salinity and hardness of the water used to dissolve the chemicals are critical for an alkaline-surfactant system. It also discusses the continuous and controlled quality check process to validate the performance of the alkaline-surfactant solution. Finally, it presents the chemical adsorption study to evaluate chemical flood potential for the future full field CEOR implementation.