bluuebunny/crossref_metadata_2025 huggingface dataset:
Estimation of Relative Permeability using the Lattice Boltzmann Method for Fluid Flows in a Cretaceous Formation, Abu Dhabi
Authors: Grader Avrami , Mu Yaoming , Toelke Jonas , Baldwin Chuck , Fang Qian , Carpio Gustavo , Stenger Bruno , Al Dayyani Taha , Kalam Zubair
Published: February 2011

A set of Petrophysical properties including porosities, absolute permeabilities, resistivity indices, elastic properties and Archie’s cementation exponent "m" were determined for a number of carbonate core plugs representing four common reservoir rock types (RRTs) of the a Cretaceous Formation Abu Dhabi. The same core plugs were then used to estimate SCAL properties including water-oil relative permeabilities using digital rock physics (DRP). DRP is referred to in this paper as the combination of advanced 3D imaging techniques such as X-ray computed tomography (CT) scanning, and the use of the Lattice Boltzmann Method (LBM) for fluid flow modeling.

The plugs were scanned, using X-ray Computed Tomography (CT), at several scales to establish the distribution of macro- and micro-porosity fractions of the carbonate samples, and identify the primary flow units. Comparison of direct measurement results with the LBM-based modeling was used as a validation of its practical ability to predict two-phase flow properties for carbonates for carbonates. Results of this study indicated that the LBM-based method achieved a good to reasonable prediction for several reservoir characterization properties such as residual fluid saturations. Some deviations were present and discussed. Finally, an up-scaling process for determining water-oil relative permeabilities for a carbonate sample exhibiting a bimodal porosity distribution was presented using one of the cores in the study as an example.
Meeting the Challenges in Developing a Mega-Field with Electrical Submersible Pumps
Authors: Al-Ali Mohammed , Warsi Syed A. , Al-Arnaout Ibrahim
Published: February 2011

Saudi Aramco is famous for making history in the oil industry; the recent jewel in the crown is the state-of-the-art development of intelligent fields with electrical submersible pumps (ESPs).

The commitment of developing the world’s largest oil increment development in history is itself a challenge. This challenge becomes enormous, if the field is to be produced using ESPs.

The challenges evolved everything from ensuring the reliability of the ESP equipment, handling half a dozen ESP installations at a time, applying consistent installation standards across all ESP installations and maintaining high installation quality for all wells. The wells are completed with downhole sensors and the state-of-the-art supervisory control and data acquisition (SCADA) system, which has the capability to remotely operate the ESPs. In this regard, one of the challenges was to ensure equipment integrity while opening and closing the wells remotely. Developing the required work force to handle the installations and subsequently optimizing the ESP performance was another huge challenge.

This paper presents how Saudi Aramco took up to these challenges and completed the field before the target date with the best ESP installation results. The post commissioning ESP failure rate in one year is the best record in the company.
Optimization and Design of Carbon Dioxide Flooding
Authors: Odi Uchenna , Gupta Anuj
Published: February 2011

Increasing energy demand coupled with public concern for the environment has placed the oil industry in an awkward position as profit-making energy provider and protector of the environmental. Today fossil fuels are the most efficient at meeting the global energy needs but have the undesirable outcome of potentially harming the environment due to production of carbon dioxide. Carbon dioxide flooding of oil reservoirs is a proven method for increasing oil production by using the miscible interactions between reservoir oil and carbon dioxide. Carbon dioxide flooding is beneficial to the environment and to petroleum producers because it uses the harmful carbon dioxide as the main agent to increase oil production. The main challenge in using this technology is applying laboratory data to its design and optimization.

The objective of this work is to develop a strategy for applying laboratory data to the design and optimization of carbon dioxide flooding process. To accomplish this, reservoir simulation studies were conducted based on carbon dioxide laboratory data. Carbon dioxide laboratory core flood results were studied and modeled using a reservoir simulator. Once there was a match between laboratory data and core flood simulations the results were used to simulate field scaled carbon dioxide flooding.

Results of these simulation studies were used to perform optimization using adjoint based algorithms and non adjoint based algorithms. Adjoint based optimization algorithms require access to simulator code while non adjoint based algorithms do not require access to simulator code. A comparison of both methods is predented in this work to show their advantages and disadvantages. This work will address best practices in applying laboratory data to simulation and optimization studies.

The work-flow presented in this work can be used to design and optimize field carbon dioxide floods. These results will serve as a basic guideline in applying laboratory data to full field carbon dioxide flood optimization.
Techno-Economic Modeling & Conceptual Design Optimization of CCS Facilities using Value Engineering & Multi-Objective Stochastic Algorithm
Authors: Mossolly Mounir
Published: February 2011

Profound scientific insight into the carbon cycle and deeper understanding of the potential consequences associated with risks of climate change, along with a recognized public awareness about the link between global warming and human activity, has put the issue of finding and approving mitigation actions in the top national & international agendas. On the other hand, the ever increasing need of energy; necessary for economic growth, and the expected strategical reliance on fossil fuels and coal as a major energy source in the foreseeable future, will definitely lead to a dramatic increase in carbon generation. Eventually, an effective mitigating action can only be achieved by capturing the carbon release, or emission, to atmosphere rather than by cutting-down carbon generation. Even though the full scale deployment of integrated CCS facilities is still immature, yet it is very promising. The technical feasibility of the component technologies has been proven successful. Applications such as Carbon Capture in large ammonia plants, CO2 transportation via pipelines and transport ships and Carbon injection for Enhanced Oil Recovery (EOR) are already in operation. The real challenge for constructing & operating CCS facilities is financial & political rather than technical. Huge investments are required globally on a large scale and need to be economically and socially justified. It is estimated that building an associated Carbon Capturing facility along with a Power Generation plant may double the capital cost and increase the running cost up to 1.5 times, as a consequence it is thought that the price of electric power to be paid by the end-users will increase by at least 50%. This economic “penalty”, sensed at the short term, will raise serious public concerns. Thus there is an urgent need to find feasible financial models for deploying CCS technology with the minimum cost possible. Such a task requires the design optimization of CCS facilities based on techno-economic models. Techno-economic models based on mathematical formulation for the partial components of CCS facilities are readily available in the literature, but still there is a necessity to integrate these component models together in a one analytical model to view the picture as a whole, after all, the complete CCS train will be operating synchronously as one train entity. Once such an integrated model is available, an optimization problem can be formulated, and a technically feasible and financially attractive solution can be found to achieve the minimum total cost with the optimum design variables. Cutting down costs will be enhanced with time, following the trend of the learning curve in this field. This paper presents a methodology for implementing design optimization of CCS facilities at the conceptual level by simulating various combinatory scenarios, for finding the most economically attractive & technically feasible solution.
Development of Structural Regional Acceptance Criteria for Existing Fixed Offshore Structures in the Arabian Gulf
Authors: Yasser Mohammed
Published: February 2011

The Joint Industry Project (JIP) is a worldwide project that concerns the development of guidance in the form of a draft API Recommended Practice (API RP2 SIM) that addresses SIM (Structures Integrity Management) issues for existing fixed steel offshore structures around the world. It also concerns the Preparation of a methodology that can be used to provide a consistent minimum reliability (against environmental overload) for offshore platforms located in different regions around the world and which is referred to as Regional Acceptance Criteria (RAC).

As a member participant in the JIP, ADMA-OPCO took the initiative to develop the Arabian Gulf Regional Acceptance Criteria (RAC). A number of structures were selected for the study representative for the range of structural types and robustness across the fleet of structures composed of about 277 platforms. It involved performing structural pushover analyses for the selected structures and reliability analysis, the work involved determination of the target structural reliability, which equates to an acceptable probability of failure (PF) which is typically a function of the consequence of failure of the platform. The maximum acceptable annual failure probabilities for HIGH, MEDIUM and LOW consequences of failure categories of the whole fleet were determined.

The above target PF’s were converted into equivalent RSRs (reserve Strength Ratios) and dead load factors as a RAC.
Summary of Environmental Issues, Mitigation Strategies, and Regulatory Challenges Associated With Shale Gas Development in the United States and Applicability to Development and Operations in Canada
Authors: Arthur J. Daniel , Coughlin B. J. , Bohm B. K.
Published: February 2011

This paper will summarize key environmental and regulatory issues associated with Shale Gas development in major shale plays in the United States, actions taken by environmental non-governmental organizations, government, and industry on these issues (including mitigation strategies). Further, the paper will present the current and future pictures of these issues and the applicability of these issues to Shale Gas development in Canada.
Unconventional Resource Development and the Role of the Regulator
Authors: Eynon G. , Hill C. , Goodman T.
Published: February 2011

Alberta's Energy Resources Conservation Board (ERCB) has regulated oil and gas resource development for almost 75 years. Throughout most of that time the industry and the regulator were concerned with conventional oil and gas resources. In the last decade or so the emphasis has shifted, for several reasons, towards unconventional resources—in situ bitumen, tight oil, tight gas, deep- or basin-centred gas, coalbed methane (CBM), shale gas, and in situ coal gasification.

The characteristics of these resources, as well as the technologies required to develop them, create the need to modify the ERCB's regulatory framework. This is integral to reaching the ERCB's vision of being The Best NonConventional Regulator in the World, capable of dealing with the pressing issues of the future energy development in Alberta. Given the realities of the changing resource base, unconventional resources are a priority, and the ERCB needs to adopt non-conventional ways of regulating their development.

The ERCB has already adapted the regulatory framework to deep/basin-centred/tight gas, coal bed methane, and in situ bitumen. The ERCB responded with new regulatory structures—Development Entities for CBM and Deep Basin gas; control wells for CBM; commingling of production streams from coal-sand sequences—to more effectively manage the development of some of those resources. After only a few years of operational experience, and with industry feedback, we have already improved the efficacy of some of these approaches and continues this effort as an ongoing practice.

Moving to the next level, however, requires some substantively different approaches. The ERCB's Unconventional Gas Regulatory Framework Project is intended to identify new ways of regulating and facilitating such resource development. It is being done with the consultative input of knowledgable stakeholders. We have already determined the major regulatory risks, and are focusing on developing ways to mitigate them with the appropriate level of necessary regulation or other, non-regulatory means.
Multicomponent Seismic Monitoring of CO2-Enhanced Oil Recovery
Authors: Benson R. D.
Published: February 2011

Time-lapse (4-D) seismic data is often able to detect changes related to the injection of CO2. However, to quantify these changes is problematic. Understanding the CO2 injection process is critical to relating the seismic response to changes within the reservoir. In most CO2 injection projects, a pure liquid CO2 is initially injected into an oil reservoir, combining with the oil, resulting in the oil swelling and becoming more mobile. Reservoir changes include variations in fluid saturation, compressibility, phase and density along with changes in reservoir temperature and pressure.

Time-lapse (4-D), multi-component (9-C) seismic data has been acquired, processed and interpreted in three oil fields that have undergone CO2 injection. Vacuum field has been monitored with four seismic surveys during an EOR project in the San Andres formation with CO2 being injected over a 200 meter zone. Weyburn field has been monitored with three seismic surveys during an EOR project in the fractured Midale member of the Mission Canyon Formation with an approximately 20 meter thick zone. West Pearl Queen field has been monitored with two seismic surveys during a CO2 sequestration test in a 12 meter thick Queen Formation.

Combining the geologic, geophysical and petroleum engineering data allows an integrated approach to interpreting the time-lapse anomalies associated with CO2 injection. Integrating the multi-component seismic data allows the separation of the fluid changes from the pressure changes, allowing a much more definitive interpretation of the anomalies associated with the CO2 injection process. Multi-component seismology is critical in monitoring CO2 movement in the Vacuum, Weyburn, and West Pearl Queen fields.
Evaluating Old Wells for Conversion to CO2 Injectors: Experience From the Rousse Field
Authors: Miersemann U.. , Loizzo M.. , Lamy P..
Published: February 2011

The RSE-1 well operated by Total is located within the Rousse field in the southwest of France. The 43 year-old well, a gas producer from a now depleted reservoir has undergone extensive research in order to determine its suitability for CO2 storage. The main objective, in terms of containment, is to avoid that the injected CO2 migrates back to the atmosphere or to potable aquifers. Existing wells are often identified as a potential weak point in the containment system, because cement, casing and elastomers can be degraded by CO2 over time. Since any defects within the cement sheath may accelerate this aging mechanism, the material behind the casing should be fully characterized especially across the caprock.

Cement bond log data was available from the 43 year old RSE-1 well, which only gave a qualitative indication of the casing-cement bond, but did not allow a detailed characterization of the material behind the casing. To gain more detailed information, new cement evaluation logs were acquired over the lower 905 m of a 2000 m thick caprock using a new generation 3D ultrasonic cement imager coupled with an array sonic imager. The use of different, independent measurements revealed good casing-cement bond that could be compared to the original logs from 1967 to confirm no degradation over the production life of the well. However, annulus imaging revealed breakouts and a very eccentered casing (almost touching the borehole wall), both of which led to the presence of mud pockets. Detailed evaluation of these pockets indicated that they are not connected and that zonal isolation over the 836 m cemented section of the caprock is indeed achieved. Modeling of cement imaging data also suggested good cement-formation bond, without any external microannulus presence.

Detailed characterization of the material behind casing, casing eccentralization and intermittent mud pockets provided an improved understanding in terms of well integrity. The results showed that the RSE-1 well nevertheless provides adequate hydraulic isolation for the injection of CO2 and that the cement sheath can therefore be eliminated as a potential weak spot in terms of containment.
CCS and CO2-Storage Possibilities in Hungary
Authors: Kubus P..
Published: February 2011

MOL (Hungarian Oil and Gas Company) in cooperation with ELGI (Hungarian National Research Institute-) recently have completed a screening study in order to determine the CO2 storage potential of HC fields operated in Hungary. Altogether 180 oil or gas reservoirs were involved into the investigation. Integrated data bases were available for the specialists for determination of potential volumetric of the fields. To accelerate the screening process relating to the deep saline aquifers a new methodology was worked out which based on the compressibility of the formations and the highest applicable overpressure. The details of this solution will be presented in details. Based on the conclusions of this study a group of the potential fields were set up providing an important input to the ongoing feasibility study.

As a second step, a desktop survey of the whole CCS value chain was concluded. The biggest existing emitters were mapped with their yearly and daily CO2 output and with the operating technological solutions. Third element of the investigation was the determination of the possible transportation routs of the captured CO2. This integrated approach seemed to be a solid base to determine the optimal connections between the target storage fields and the emitters. The details of the screening process and the target capacities will be summarized in the paper.

A Consortium (MOL, Matra Power Plant, ELGI) established for preparing a feasibility study of the most possible CCS project possibility in Hungary, details will be found in the paper as well, showing the technical solutions of capture, transport and storage plans with economics issues.

Preliminary economics resulted that a full value chain CCS might be viable only with at least 50% EU subvention (both CAPEX and OPEX side), and relatively high and continuously growing CO2 prices (40EUR/t in 2012 growing up to 55 EUR/t in 2020) are the most critical financial issues for the successful project initialization.
Tengiz Reservoir Uncertainty Characterization and Modeling
Authors: Peake W. T. , Camerlo R. H. , Tankersley T. H. , Zhumagulova A..
Published: February 2011

Probabilistic production forecasting at Tengiz is largely driven by reservoir uncertainty. Reservoir uncertainty is most effectively synthesized and quantified through simulation modeling. Early in the construction of a new Tengiz dynamic model, fundamental reservoir uncertainties were identified and evaluated. This allowed for model ‘building blocks’ to be developed with different characterizations to encompass key uncertainties.

Key uncertainties, which can significantly impact future production under primary depletion and sour gas injection, have been described. These include typical uncertainties such as porosity, irreducible water saturation, hydrocarbon fluid properties, oil-water contact levels, rock compressibility, geologic baffles, and relative permeability. Unique uncertainties specific to Tengiz include geometry and density of the natural fractures, and reservoir heterogeneity.

Considerable production history and a large reservoir surveillance database provided input for rigorously characterizing and subsequently validating the range of each uncertainty. After ranges were established, appropriate model realizations were created. A wide range of reservoir models were obtained by selecting combinations of high/mid/low realizations for each uncertainty. Using experimental design (ED), reservoir simulations were conducted to test uncertainty ranges against field history. A quantitative history match and statistical analysis were developed to objectively judge the appropriateness of uncertainty values. Uncertainties with the largest overall impact on the history match are: fracture density, platform horizontal permeability, compressibility, and platform heterogeneity.

This case study demonstrates how analysis of reservoir uncertainties can be: (1) captured in static and dynamic reservoir models and (2) validated through ED and quantitative history matching. This study employs state-of-the-art technologies to evaluate model uncertainties of a giant carbonate reservoir undergoing both depletion and miscible gas drives. The range of reservoir models subsequently developed will be of great value in creating robust probabilistic reservoir forecasts to optimize field operation and future development.
Design, Operations, and Interpretation of CO2 and Water Injection Test in Low Permeability Saline Aquifer
Authors: Kumar Viren , Garnett Andrew , Kumar Giridhar , James Simon , Trivedi Bhaskar , Salunke Sarita , Rao Narsimha
Published: February 2011

ZeroGen-11 is the first pilot CO2 injection well, air drilled by ZeroGen in the North Denison Trough. Its objective was to evaluate low permeability saline aquifers for suitability to commercial scale CO2 sequestration by investigating the injectivity of super-critical CO2 and brine, reservoir ‘k.h’ (permeability-thickness), reservoir continuity. Key activities were the CO2 and water injection test design, well site operations and the interpretation of the ZeroGen-11 CO2 and water injection fall-off test data.

A series of CO2 injection tests and a single water injection test were carried out in ZeroGen-11. The detail design of the tests and selection of various intervals were based on continuous cored data, rock typing, and low cost appraisal wells. The materials for well tubulars were CO2 resistant (13Cr).

Pilot operation activities commenced in mid 2009 and, being the first open-hole CO2 pilot in saline aquifer with unusually low permeability, they faced significant challenges. Operational data from the Australian wellsite was analyzed real time at the Shell Bangalore Technology Centre "Collaborative Work Environment" by an integrated team of discipline specialists which helped for the optimization of ZeroGen operations. The operational experience gained is valuable for low rate injection tests, at high pressures in an open-hole interval under compressive stress regime where fracture gradients as high as 1.1 psi/ft are possible.

The test results established supercritical injectivity of CO2 in matrix condition for high permeable Catherine Sandstone interval at rate of 150 TPD and in low permeability Aldebaran formation at 2-3 TPD. The well test interpretation gives ‘kh’ in the range of 1 md.ft for Aldebaran and 240md.ft for high permeability Catherine Sandstone. The water injection test provides a reasonable calibration point to determine CO2 injectivity, and is expected to be useful in appraisal campaigns in saline aquifers. It is also noted that the CO2 injection test did not show a two boundary signature in the pressure derivative curve that was clearly observed for the water injection test as the presence of CO2 zone near wellbore mask the effects of a boundary signature.
Permeability Estimation for Large-Scale Potential CO2 Leakage Paths in Wells Using a Sustained-Casing-Pressure Model
Authors: Tao Qing , Checkai Dean , Bryant Steven L.
Published: February 2011

Large-scale geological storage of CO2 is likely to bring CO2 plumes into contact with a large number of existing wellbores. Estimating the flux of CO2 along a leaking wellbore requires a model of fluid properties and of transport along the leakage pathway. Wells that exhibit sustained casing pressure (SCP) in an intermediate annulus have a leakage path along a cement/steel interface, or within the cement in the annulus. The former path is analogous to a leakage path along a cement/earth interface outside the casing. The latter path can occur in cement outside the casing. Thus the likely magnitude of the permeability of leakage paths outside the well can be estimated from the permeability of these analog paths. A sustained casing pressure (SCP) model yields information about effective permeability of the pathway.

By choosing reasonable ranges for other well construction parameters, we apply the SCP model to obtain a range of effective permeabilities for a well based on a measured casing pressure build up history. We illustrate the approach with several field examples. For a relatively slow pressure build up (several psi/day), the permeability of the leakage path is in the range of microdarcy to hundreds of microdarcy. Fast pressure build up (thousands psi/day) indicates permeabilities in the range of tens of millidarcy to hundreds of millidarcy.

To account for the uncertainty in wellbore construction parameters, we calculate the distribution of effective permeability of a leaky well using Monte-Carlo simulation. The resulting permeability shows an approximately log-normal distribution skewed toward the maximum possible value. The expected value and a confidence interval are obtained for each well, which represents the most probable permeability of the well for a given pressure build up. For the wells studied here the expected values range from 10 microdarcy to 100 millidarcy. The expected leakage path permeability correlates reasonably well with pressure build up rate. This is to be expected from Darcy’s law, and thus a strong correlation between leakage path permeability and other characteristics of the wells in this sample does not exist. Obtaining the statistics of the expected leakage path permeability will thus require more observations of SCP wells.

The effective permeability of a leaky well is essential in calculating the CO2 leakage flux. Under the assumption that a leaky well encountered by a CO2 plume has a leakage pathway with the similar properties to an SCP well, we calculate the CO2 flux for the best, worst and most probable scenarios for the example wells. In the most probable scenario of CO2 flux, we calculate the expected CO2 leakage rate. Slow leakage yields a 0.1 kg/y CO2 rate while fast leakage could have a rate of 1000 kg/y.
Experimental Study on Optimum Half-Cycle Slug Size of Water Alternating Gas Under Tertiary Miscible Carbon Dioxide Flooding
Authors: Nuryaningsih L.. , Jiang H.. , Adidharma H..
Published: February 2011

The effect of half cycle slug size (HCSS) on Water Alternating Gas (WAG) performance in tertiary miscible carbon dioxide (CO2) flooding is experimentally investigated. Different half cycle slug size influences the fluids mobility and the contact time between the injected fluids and oil, and hence to achieve the best possible displacement efficiency, an optimum water/gas half cycle slug size could exist and deserves investigation.

Coreflood experiments are performed in Berea sandstone core, from which the WAG performance, such as percent oil recovery, tertiary recovery factor, and CO2 utilization factor are determined. The core flooding experiments are conducted at 60 °C and at miscible condition, i.e., at a pressure 20% above the minimum miscible pressure (MMP) of the oil sample. The experiments utilize Cottonwood Creek crude oil and artificial brines. The injection and connate brine contain 33.33 wt% CaCl2 and 66.67 wt% NaCl with salinities of 16000 ppm (mg/L) and 30000 ppm, respectively. In every core flood test, alternate cycles of brine and CO2 with a WAG ratio of 1:1 are injected with half cycle slug size ranging from 0.05 to 0.75 PV.

The results show that for the system of interest, the optimum HCSS is 0.1 PV, in which the CO2 usage is only 0.6 PV to reach a high tertiary oil recovery of 40.63%. An HCSS higher or lower than 0.1 PV gives lower oil recovery. When HCSS is lower than 0.1 PV, the system gives lower oil recovery because some of the gas is trapped by water and keeps staying in the core instead of displacing oil. Meanwhile, an HCSS higher than 0.1 PV results in larger clusters of CO2 and water, thus water inefficiently controls CO2 mobility, which makes the CO2-oil contact time and interfacial area for mass transfer decrease and gas breakthrough occurs prematurely.

This experimental study is an essential effort to obtain better understanding the effect of half cycle slug size on WAG performance, which has never been experimentally investigated before. The understanding is critical for optimizing the WAG performance.
Effect of Aquifer Heterogeneity, Brine Withdrawal, and Well-Completion Strategy on CO2 Injectivity in Shallow Saline Aquifer
Authors: Tiamiyu O. M. , Nygaard R.. , Bai B..
Published: February 2011

The most promising near term solution to reduce CO2 emissions is to capture the CO2 produced from coal and gas fired power plants and inject it into deeply buried saline aquifers. However a large amount of these plants are far away from deep sedimentary basins and therefore alternative solutions have to be sought. Detailed computer simulation, using compositional numerical model software CMG-GEMGHG, was used to study the effects of aquifer anisotropy (heterogeneity), well completion technique (perforation and well orientation), brine production and injection rates on CO2 injectivity, and capability to retain and store reasonably large amount of CO2 for an extended period of time. The objective of this study is to find the optimal combination of operational parameters (injection rates, well completion techniques and brine withdrawal strategy), and how the interplay of these parameters with aquifer anisotropy (heterogeneity) affects, and can be manipulated to optimally harness CO2 storage potential and leakage risk mitigation in shallow saline aquifers.

Injected CO2 exists in three main forms in the aquifer, supercritical, dissolved and aqueous forms with amount depending largely on prevailing formation pressure and the depth of well placement. Without brine withdrawal, horizontal injector wells with the vertical sections closed have higher CO2 injectivity compared to vertical and deviated wells with bottom half perforated. With brine withdrawal more CO2 was injected and anisotropy (heterogeneity) (Kv/Kh ratio) has significant effect on CO2 injectivity, but well perforation and orientation has negligible effect, except for an extended (85 years) injection period when aquifer pressure has reached the maximum allowable. The impact of anisotropy (heterogeneity) on CO2 injectivity was observed to decrease with increase on injection rate for injection well placed in uppermost layers. This study shows CO2 sequestration in shallow saline aquifer has significant potential. Results from this study can potentially provide guideline for well completion technique, injection rate and brine withdrawal strategy, depending on aquifer properties, that can be applied in CO2 sequestration in shallow saline aquifer.
Unique CO2-Injection Experience in the Bati Raman Field May Lead to a Proposal of EOR/Sequestration CO2 Network in the Middle East
Authors: Sahin S.. , Kalfa U.. , Celebioglu D..
Published: February 2011

Fossil fueled power generation is the largest source of carbon dioxide (CO2), which could be captured and stored. Carbon capture and storage (CCS) is one of the most important emission reduction technologies available for large stationary CO2 sources. Depleted oil and gas fields and major CO2 sources nearby are ideal areas for large scale geological storage. Injection of CO2 into a depleted reservoir can enhance the recovery of hydrocarbons. The circumstances, in fact, dictate the CO2 enhanced oil recovery (EOR) industry and a power generation sector eager to magnify the mutually beneficial link between CO2-EOR and new industrial sources of CO2.

In 1986, the TPAO (Turkish Petroleum Corporation) started the first large scale immiscible CO2 injection project in southeastern Turkey. Around one million tons per year of naturally occurring CO2 has been injected into the Garzan carbonates in the Bati Raman Field. A substantial increase in the production rate and ultimate recovery has been experienced and more is expected. The Bati Raman immiscible CO2 injection project has been acknowledged as one of the most unique and successful enhanced oil recovery (EOR) applications in the history of heavy oil in fractured limestone reservoirs.

There are nearly 50 oilfields in Turkey, and a significant proportion of them would be potentially suitable for EOR. If sufficient volumes of CO2 were economically available, many of these could produce incremental oil for an extended period. It is a fact that sedimentary basins in the Middle East are typically carbonates and this limits the selection of EOR processes significantly. Having observed CO2 injection as an excellent choice for carbonates through the Bati Raman experience, one may extend the CO2 network idea to the whole region. This will not only activate the enormous EOR potential in the mature fields of the Middle East but also the permanent storage of CO2 through a common effort.

The utilization of captured CO2 for EOR will become feasible if CO2 recovery plants with a higher CO2 content give an attractive CO2 delivery cost and emission rights can be traded in the carbon market which was introduced by the Kyoto Protocol. The major challenge would be how to formulate a working and acceptable model between petroleum and power sectors and, to establish a market mechanism to ensure that this system becomes economically feasible.
Quantifying the Risk of CO2 Leakage Through Wellbores
Authors: Loizzo M.. , Akemu O. A. , Jammes L.. , Desroches J.. , Lombardi S.. , Annunziatellis A..
Published: February 2011

Leakage through new or existing wellbores is considered a major risk for carbon dioxide (CO2) geological storage. Long-term effective containment of CO2 is required and the presence of millions of suspended or abandoned wells exacerbates the potential risk in mature hydrocarbon provinces. Accurate estimates of risk profiles can support the acceptance of geological storage and the adoption of economically effective risk prevention and mitigation measures.

Reliable data about long-term containment of CO2 is almost non-existent, so wells that exhibit a similar risk profile (such as gas storage, gas production and steam injection) should be used as proxy to assess failure rates and consequences for cemented wellbores.

Statistical data about occurrence of leaks and their consequences are analyzed to determine the risk profile of CO2 leaks. A smaller sample of data about leak rates is also analyzed to provide their statistical distribution. Rates and consequences are then compared to try and assess the order of magnitude of major and catastrophic leaks.

Hydrothermal CO2 leaks in natural analogs are also reviewed to compare the distribution of leak rates and the consequences on health, safety and environment of CO2 releases to soil and atmosphere.

Analysis of existing data will show that major leaks are likely to occur in less than 2 wells per 1,000, with the overwhelming majority of CO2 leaks being small and with limited or negligible consequences.

Given their risk profile, CO2 wellbore leaks should be addressed through a routine risk management approach. Their frequent occurrence requires effective prevention measures, such as understanding leaks and adapting and deploying practices to minimize their occurrence. On the other hand, their low impact ensures maximum effectiveness of mitigation measures, such as monitoring: since leaks can be detected long before damage ensues, they can be observed to predict their long-term consequences and to plan the most effective intervention without unnecessary immediate operation shut-downs.

In conclusion, the recommended course of action is to focus on risk prevention and early detection. This implies the evolution from a "no leaks" attitude (even for negligible leak consequences) to one that seeks no damage and relies on tight surveillance.
Tertiary Oil Recovery and CO2 Sequestration by Carbonated Water Injection (CWI)
Authors: Kechut N.I.. I. , Riazi M.. , Sohrabi M.. , Jamiolahmady M..
Published: February 2011

The increasing availability of the anthropogenic carbon dioxide (CO2) and the drives to reduce its concentration in the atmosphere has increased the interest in CO2 injection for improving the oil recovery in maturing oil reservoirs. Many of these reservoirs are being waterflooded to sustain the oil production. Instead of injecting plain water, injecting carbonated (CO2-enriched) water could bring additional oil recovery and added benefit of safe storage of CO2. In carbonated water injection (CWI), CO2 is dissolved in the injected brine prior to injection and then transported through the reservoir by the flood water. As a single phase, carbonated water mobility contrast with oil is more favourable than in the CO2 gas-oil system thus improves sweep efficiency and retards CO2 breakthrough. The slightly higher density of the carbonated water than the unadulterated water would induce the injected CO2 to slump towards the bottom of the reservoir, eliminating the risk of buoyancy-driven leakage thus securing storage.

This paper presents the results of an integrated experimental and numerical simulation study of tertiary CWI. A series of high pressure flow visualisation and coreflood experiments as well as compositional simulation have been carried out to evaluate the process. A North Sea crude oil and brine were used at a pressure typical of real reservoir conditions.

The visualisation experiments in high-pressure glass micromodels reveal that the oil swelling from CO2 diffusion into the oil and the subsequent oil viscosity reduction, coalescence of the isolated oil ganglia and flow diversion due to flow restriction in some of the pores as a result of oil swelling and the resultant fluid redistribution are the main mechanisms of oil recovery by the tertiary CWI. There was also evidence of micromodel surface becoming more water wet that could also play a role in the oil recovery. The coreflood tests results clearly show that the post waterflood CWI could remobilize the remaining trapped oil in the watered-out core that leads to significant additional oil recovery. A very gradual (dissolved) CO2 breakthrough exhibited in this process is a significant advantage over the sudden CO2 breakthrough problem commonly faced in the conventional CO2 flooding. CWI is also highly potential as CO2 storage injection strategy as demonstrated by almost 50% of the total volume of CO2 injected (in carbonated water) was being stored at the end of the test. There is a challenge in simulating the physics of the CWI process using the commercially available reservoir simulators which will also be discussed.
A Survey of CO2-EOR and CO2 Storage Project Costs
Authors: Jablonowski C.. , Singh A..
Published: February 2011

For CO2 enhanced oil recovery (CO2-EOR) and CO2 storage projects, cost estimates have wide-ranging impacts on site screening and feasibility studies, concept selection, development planning, and production optimization. Good cost estimating practice requires technical knowledge about the project, a comprehensive scope, and a systematic approach. However, the quality of a cost estimate is probably most dependent on the quality of the data on which it is based. In the case of CO2-EOR and CO2 storage projects (CO2 projects), cost estimators face significant challenges regarding the availability and quality of data. The purpose of this paper is to organize and consolidate information on capital and operational costs for CO2 projects. A review was undertaken to identify and describe sources for cost data by major project components. There are sections for drilling, surface facility capital cost, and operation and maintenance cost. This survey can serve as a departure point for CO2 project cost estimators.
Saline Reservoir Storage in an Active Oil Field: Extracting Maximum Value From Existing Data for Initial Site Characterization, Southeast Regional Carbon Sequestration Partnership (SECARB) Phase IIII Anthropogenic CO2 Test at Citronelle Field
Authors: Petrusak R.. , Cyphers S.. , Bumgardner S.. , Hills D.. , Pashin J.. , Esposito R..
Published: February 2011

For large-scale carbon dioxide (CO2) injection and storage, saline formations offer vast storage capacity, often in multiple geologic formations, or multiple storage reservoir horizons within a single formation. Challenges for characterizing CO2 storage reservoirs in specific saline formations may include limited subsurface data, unproven geologic traps and lack of any production infrastructure available for injection and monitoring operations. Active oil fields offer advantages for CO2 sequestration in saline formations that address such challenges. Advantages of active oil fields include proven structural traps and reservoir seals; confirmed saline storage horizons; existing field data including geophysical well logs, seismic data, core data, formation water analyses and reservoir pressure tests; existing infrastructure for access and monitoring; and potential use of CO2 in enhanced oil recovery. Such advantages are substantial, but active oil fields can also present unique hurdles for CO2 storage in saline formations. These include old and incomplete well data and geophysical logs; confirming the integrity of cement through the saline formation and confining unit (if located above the oil reservoir); and remediating existing wells.

The Southeast Regional Carbon Sequestration Partnership (SECARB) Phase III Anthropogenic Test is a large-scale demonstration of integrated CO2 capture, transport and storage planned for Citronelle field, in Mobile County, Alabama.1 Anthropogenic CO2 from a coal-fired electric generating plant, Alabama Power’s Plant Barry, will be captured and transported to Citronelle field.2 During 2011 to 2014, up to 182,500 tonnes of CO2 will be injected annually into the Lower Cretaceous Paluxy Formation, a saline formation that contains multiple reservoir sandstones and is located above the oil reservoir. This paper describes the initial characterization effort, which used all available field and regional data, to build a reservoir framework for the Paluxy Formation at Citronelle for initial assessment of injectivity, storage capacity and fate of injected CO2. The initial characterization of the Paluxy Formation demonstrates a successful approach for estimating key saline reservoir parameters including porosity, permeability, sand thickness and continuity from an incomplete existing data set in an active oil field. A robust geologic data collection effort is planned for the CO2 injection and observation wells to be drilled at the Anthropogenic Test site during 2011. The new data will be integrated with the existing Paluxy data set at Citronelle field to validate, refine and expand the initial characterization of the CO2 storage reservoir sandstones.
Thermal Aspects of Geomechanics and Induced Fracturing in CO2 Injection With Application to CO2 Sequestration in Ohio River Valley
Authors: Goodarzi S.. , Settari A.. , Zoback M.. , Keith D. W.
Published: February 2011

Ohio River Valley is considered a potential site for CO2 storage since it is in close proximity to large CO2 emitters in the area. In a CO2 storage project, the temperature of the injected CO2 is usually considerably lower than the formation temperature. The heat transfer between the injected fluid and rock has to be investigated in order to test the viability of the target formation to act as an effective storage unit and to optimize the storage process.

A coupled flow, geomechanical and heat transfer model for the potential injection zone and surrounding formations has been developed. All the modeling focuses on a single well performance and considers induced fracturing for both isothermal and thermal injection conditions. The induced thermal effects of CO2 injection on stresses, displacements, fracture pressure and propagation are investigated. Possibility of shear failure in the caprock resulting from heat transfer between reservoir and the overburden layers is also examined.

Displacements will be smaller for the thermal model compared to isothermal model. In the thermal case, the total minimum stress at the wellbore decreases with time and falls below the injection pressure quite early during injection. Therefore, fracturing occurs at considerably lower pressure for the thermal model. The coupled thermal and dynamic fracture model shows that thermal effects of injection could increase the speed of fracture propagation in the storage layer depending on the injection rate. These phenomena are dependent primarily on the difference between the injection and reservoir temperature. An optimization algorithm for injection temperature is discussed based on limiting the maximum fracture length and minimizing the risk of leakage from thermal effects of CO2 storage while improving the injection capacity.

Incorporation of thermal effects in modeling of CO2 injection is significant for understanding the dynamics of induced fracturing in storage operations. Our work shows that the injection capacity with cold CO2 injection could be significantly lower than expected, and it may be impractical to avoid induced fracture development. In risk assessment studies inclusion of the thermal effects will help prevent the unexpected leakage in storage projects. The methodology developed will play an important role in process optimization for maximizing the injection capacity while maintaining the safety of storage.
Experimental Evaluation of the Flue-Gas Injection of Barrancabermeja Refinery as EOR Method
Authors: De La Ossa J. E. , Wallens A. Bejarano , Anaya A. Florez , Santos N. S.
Published: February 2011

Because of its petrochemical processes Barrancabermeja refinery produces a considerable amount of flue gas daily. The Llanito oil field has an original oil volume of 314 million barrels (MBls) and it has produced 37.9 MBls up to December 2009, which corresponds to a recovery factor of only 12%, being really low for 50 years of exploitation.

The application of an enhanced oil recovery process represents an alternative for improving the final recovery factor. The availability of sources (Water, gas, chemicals, steam, etc) and the reservoir characterization dictate the feasibility of the project according to a study carried out. An environmentally undesirable by-product resulting from refining processes such as flue gas (Nitrogen + CO2) becomes important when used as raw material in the secondary or tertiary recovery of oil which affects the increase in production and the final recovery of hydrocarbons.

This study evaluated experimentally the effect of the injection of the Barrancabermeja refinery´s flue gas as an enhanced oil recovery method applied to B Sandstone of the Llanito oil field. The volume of the refinery´s flue gas was characterizated and calculated; a study of fluid-fluid interaction was carried out between the flue gas and petroleum at reservoir conditions. The interaction between reservoir fluid and the porous media was evaluated and the best flue gas injection mechanism was determined in order to increase the recovery factor for the B sands of Llanito oil field. In addition to increase the final recovery factor, the study aims to reducing flue gas emissions and consequent environmental benefit.