Oil Recovery Field Research Articles

MEOR Field Test at Block Luo801 of Shengli Oil Field in China

A microbial enhanced oil recovery (MEOR) field test has been performed for 10 consecutive years at Block Luo801, whose temperature is 75–80°C in Shengli Oil Field in China. After the implementation of MEOR, the produced fluid samples from the oil wells were analyzed and found an increase in the density of bacteria and archaea in waterphase stabilizing at 103–4 cell/ml, which suggesting the nutrient injected has activated the indigenous bacteria in the reservoir. These indigenous bacteria activities were enhanced to prevent the water cut from rising up in the block so as to increase the oil output. Up to December 2010, the cumulative increased production of oil has been 9.75 × 104 t with the total output surpassing that of water flooding oil recovery (WFOR) by 3.35%. Considering the cost of injected microbial fluid and nutrient, oil increased per tonne costs about RMB339.56.

Rheological Properties and Salt Resistance of a Hydrophobically Associating Polyacrylamide

The rheological properties of electrolyte solution of a hydrophobically associating acrylamide-based copolymer (HA-PAM) containing hydrophobically modified monomer and sodium 2-acrylamido-2-methylpropanesulfonic sulfonate were investigated in this paper. The study mainly focussed on effects of electrolyte concentration, temperature, and shear rate on the solution rheological properties. HA-PAM exhibited much stronger salt tolerance and shearing resistance than the commonly used partially hydrolyzed polyacrylamide, and has great potential for application in tertiary oil recovery of oilfields with high salinity. The salt resistance mechanism of HA-PAM in solution was investigated by combining molecular simulation and experimental methods. The structure–performance relationship of the salt-resisting polymer may provide useful guidance for design and synthesis of novel water-soluble polymers with high salt resistance.

Ca2+ Ion Responsive Pickering Emulsions Stabilized by PSSMA Nanoaggregates

A novel Ca(2+) ion responsive particulate emulsifier, which is based on copolymer nanoaggregates, is reported in this work. Results from dynamic light scattering (DLS) and cryo-transmission electron microscopy (cryo-TEM) indicate that the formation of poly (4-styrenesulfonic acid-co-maleic acid) sodium salt (PSSMA) nanoaggregates is strongly dependent on Ca(2+) concentration. The PSSMA copolymer only aggregates above a critical Ca(2+) concentration (0.2 M) with an average diameter of 10-40 nm. After dilution with water, PSSMA nanoaggregates are rapidly redissolved again. On the basis of the properties of PSSMA nanoaggregates, Ca(2+) ion responsive Pickering emulsions were successfully prepared. At high Ca(2+) concentrations, the emulsions with high stability against coalescence can be prepared with the size in the submicrometer range as determined by DLS. Cryo-TEM and dynamic interfacial tension results confirm the adsorption of PSSMA nanoaggregates at the interface, which is the key to the stability of the emulsions. More importantly, rapid demulsification can be achieved by dilution with water on demand. It is because, upon dilution with water, PSSMA nanoaggregates undergo a transition from stable nanoaggregates to individual polymer chains, which leads to interfacial desorption of nanoaggregates and rapid demulsification of emulsions. Thus, this finding presents a new manipulation on emulsion stability and is expected to provide a useful guidance in the fields of oil recovery, food science, environment protection, and so on.

Study of FBG Sensor in the Oil Well Logging System

This paper presents a new method of a FBG sensor for temperature measurement in the well logging system. FBG Sensors have a wide range of precise temperature measurement highlighting characteristics, at the same time, they also can realize measurement and stress more distributed measurement, which provides the key technology for real-time wellsite data acquisition, analysis, and the decision-making, as well as improves the existing oil field recovery.

A New Method of Calculating Recovery of Waterflooding Reservoir by Using Production Rate

Development characteristics of oil field during production-decreasing stage were analyzed in this paper. The ultimate recovery factor can be determined at a limit of oil production rate by investigating the relationship between production rate and recovery percent. Some physical conditions were given. Based on the mass conservation principal and seepage mechanics method, it was found that the recovery degree varies versus production rate linearly. The model prediction using the actual data of west Ng63+4oil strata in Gudong 7 region, a reservoir in Shengli oilfield of China, was performed. The results demonstrated that the linear model had well estimation of the recoverable recovery of oil fields which were at the later period of high water cut stage.

Monitoring and Modeling CO2 Behavior in Multiple Oil Bearing Carbonate Reefs for a Large Scale Demonstration in Northern Lower Michigan

The Midwest Regional Carbon Sequestration Partnership (MRCSP) is conducting large-scale CO2 injection into carbonate reefs in northern Lower Michigan, using CO2-enhanced oil recovery (EOR) fields as test beds for understanding geoscience issues and developing best practices. Depleted oil and gas fields are of regional importance as they are increasingly seen as a significant opportunity for geologic storage in Midwestern USA. The demonstration and concurrent technology transfer are aimed at promoting this early deployment option for carbon capture utilization and storage (CCUS). Three types of reef are being evaluated: late stage reefs that have already undergone significant CO2-EOR, active stage reefs with ongoing CO2-EOR, and newly targeted reefs that are in primary production. Initial modeling and monitoring results, as well as feasibility assessments of using technologies such as tracer studies, vertical seismic profiling, microseismic monitoring, borehole gravity survey, and remote sensing, are guiding the design of the long-term monitoring, verification, and accounting (MVA) program.

Synthesis and Evaluation of Anionic Gemini Surfactant

Abstract. Take the lauric acid, the ethylene diamine, the chloroacetic acid, the soda ash as raw material synthesized a new type of Anionic Gemini surfactants-N, N'-double lauroyl ethylene diamine two sodium acetate, The properties of the product were characterized, and the physical and chemical properties were determined. The experimental results can be seen that the anionic Gemini surfactants can greatly reduce the oil/water interface tension, and it has good viscosity properties, Thus deduced that the Gemini surfactants is better than the ordinary surfactant better table (world) surface activity, Can be used in the tertiary oil recovery field.

Xanthan and guar polymer solutions for water shut off in high salinity reservoirs

Abstract In this research the influence of salt concentration on the rheology of xanthan and guar solutions and their combined mixtures was investigated. Shear viscosity at wide shear rate range was measured for all solutions at various conditions of temperature, polymer concentration, mixing ratio, and salt content. It was found that while xanthan solutions were more susceptible to salt presence in the solutions which has led to reduction in shear viscosity, the viscosity of guar solutions tended to increase upon increasing salt concentration and this was equally pronounced at low and high polymer concentration, i.e. 500 ppm and 3000 ppm. Synergism was not significantly observed for the xanthan/guar mixtures at all ratios used, i.e. 1:1, 1:2, and 2:1. Salt greatly affected the rheology of xanthan/guar mixtures except for mixtures where the guar content was high. We believe that this method, i.e. combining xanthan and guar solutions, is an effective strategy to control rheology and morphology of solutions to be used in enhanced oil recovery field.

Impact of an indigenous microbial enhanced oil recovery field trial on microbial community structure in a high pour-point oil reservoir

Based on preliminary investigation of microbial populations in a high pour-point oil reservoir, an indigenous microbial enhanced oil recovery (MEOR) field trial was carried out. The purpose of the study is to reveal the impact of the indigenous MEOR process on microbial community structure in the oil reservoir using 16Sr DNA clone library technique. The detailed monitoring results showed significant response of microbial communities during the field trial and large discrepancies of stimulated microorganisms in the laboratory and in the natural oil reservoir. More specifically, after nutrients injection, the original dominant populations of Petrobacter and Alishewanella in the production wells almost disappeared. The expected desirable population of Pseudomonas aeruginosa, determined by enrichment experiments in laboratory, was stimulated successfully in two wells of the five monitored wells. Unexpectedly, another potential population of Pseudomonas pseudoalcaligenes which were not detected in the enrichment culture in laboratory was stimulated in the other three monitored production wells. In this study, monitoring of microbial community displayed a comprehensive alteration of microbial populations during the field trial to remedy the deficiency of culture-dependent monitoring methods. The results would help to develop and apply more MEOR processes.

Applications of Microbial-Enhanced Oil Recovery Technology in the Past Decade

The microbial-enhanced oil recovery method relies on microorganisms and their metabolic products to mobilize residual oil. It is environmentally friendly and easy to operate. In the past ten years, the microbial-enhanced oil recovery method has attracted a great deal of attention in both research and field applications. Previous reviews focused on microbial-enhanced oil recovery mechanisms, namely IFT reduction, selective plugging, gas production, biodegradation, and wettability alteration. This article summarizes the well-documented field cases in the past ten years. The objectives are to investigate the microbial-enhanced oil recovery mechanisms and application criteria based on field data. A total of ten field cases are reviewed, including cases in Malaysia, USA, Argentina, and China. It was concluded that most of the successful MEOR treatments were conducted for formations with a low temperature (below 55 ° C), low water salinity (less than 100,000 ppm), high water cut (above 75%), and low production rate. Reservoir permeability does not seem to determine the success of microbial-enhanced oil recovery. The current success rate for the microbial-enhanced oil recovery method stands at about 80%. With a better understanding of microbial-enhanced oil recovery mechanisms and field experiences, the microbial-enhanced oil recovery method is expected to prosper and the success rate will improve.

The Alberta Carbon Trunk Line (ACTL)

The province of Alberta is endowed with the second largest oil reserves in the world behind Saudi Arabia in the form of bitumen in oil sands, with established bitumen reserves of 27.0 109 m3 extracted from initial bitumen in place of 286.6 109 m3. This huge resource base presents enormous challenges to produce and upgrade bitumen in an environmentally responsible manner, related to potential greenhouse gas emissions. Extracting this bitumen from oil sands and thereafter upgrading it to synthetic crude oil requires extensive processing using either carbon rejection (coking) or hydrogen addition (hydrocracking). The production of hydrogen for hydrocracking necessitates emissions of CO2 into the atmosphere which contributes in a significant manner to Alberta’s greenhouse gas emissions. Enhance Energy Inc. and NorthWest Upgrading Inc., two privately funded Alberta based companies, are proposing a solution by constructing CO2 capture and a backbone CO2 gathering and distribution system from Alberta’s industrial heartland area, which is the site of current and proposed bitumen upgraders, to enhanced oil recovery fields in central and southern Alberta for ultimate sequestration of such CO2. This paper presents an overview of the project which is scheduled for operation in late 2013.

Complete genome sequence of Denitrovibrio acetiphilus type strain (N2460T)

Denitrovibrio acetiphilus Myhr and Torsvik 2000 is the type species of the genus Denitrovibrio in the bacterial family Deferribacteraceae. It is of phylogenetic interest because there are only six genera described in the family Deferribacteraceae. D. acetiphilus was isolated as a representative of a population reducing nitrate to ammonia in a laboratory column simulating the conditions in off-shore oil recovery fields. When nitrate was added to this column undesirable hydrogen sulfide production was stopped because the sulfate reducing populations were superseded by these nitrate reducing bacteria. Here we describe the features of this marine, mesophilic, obligately anaerobic organism respiring by nitrate reduction, together with the complete genome sequence, and annotation. This is the second complete genome sequence of the order Deferribacterales and the class Deferribacteres, which is the sole class in the phylum Deferribacteres. The 3,222,077 bp genome with its 3,034 protein-coding and 51 RNA genes is part of the Genomic Encyclopedia of Bacteria and Archaea project.

Successful Implementation of a Gas-Injection Trial in a Low-Permeability Carbonate Reservoir Offshore Qatar

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper IPTC 13327, ’Successful Implementation of a Gas-Injection Trial in a Low-Permeability Carbonate Reservoir Offshore Qatar,’ by Kristian Mogensen, SPE, and Soren Frank, SPE, Maersk Oil Qatar, and Rashed Noman, SPE, Qatar Petroleum, prepared for the 2009 International Petroleum Technology Conference, Doha, Qatar, 7-9 December. The planning and implementation of a lean-gas-injection trial conducted in the low-permeability Kharaib B carbon-ate reservoir of the Al Shaheen field, offshore Qatar, is described. The main objectives of the trial were to determine whether premature gas breakthrough would occur in the neighboring production wells and whether water injectivity after the gasflood would be reduced as a result of the presence of high gas saturation around the injection well. Introduction The Al Shaheen field began production in 1992 from two thin separate Cretaceous carbonate formations and an overlying sandstone formation. Field development used horizontal wells, some placed in radial patterns and others in parallel line-drive patterns of alternating water injectors and oil producers. These carbonate reservoirs are relatively thin oil columns with a large areal extent (25×45 km) with permeabilities in the 1- to 10-md range. The reservoir-fluid properties exhibit large lateral variations, with oil gravities ranging from 16 to 38°API within the same reservoir. The field contains several gas caps and shows large variations in solution gas/oil ratio (GOR) and in saturation pressures. Development studies focus on expanding of the current waterflood and on enhanced oil recovery (EOR). A promising EOR process is water-alternating-gas (WAG) injection that uses either CO2 or hydrocarbon gas as the injectant. A coordinated effort was initiated in 2006 to evaluate the scope for incremental field oil recovery. An important part of the EOR evaluation was to conduct an early gas-injection trial for a period of 6 months in the Kharaib B reservoir. The purposes of the trial were to investigate whether unexpected large-scale permeability heterogeneities exist in the reservoir, to gather gas- and water-injectivity data, and to gain experience for planning potential WAG-injection applications for the whole field. Planning Phase The most important part of the preparatory phase was to select the correct injection well for the trial to ensure that the trial objectives could be met. Once selected, the required modifications to the surface facilities then could be scheduled and a data-gathering program set up.

Geological storage of carbon dioxide: an emerging opportunity

Abstract Concerns about climate change and the need to stabilize atmospheric CO 2 concentrations are driving the development of a lower carbon future. Within this context, carbon dioxide capture and storage (CCS) is gaining momentum as a large-scale option to reduce greenhouse gas emissions. This paper reviews the rationale and potential scale of CCS, the status of geological storage options and lessons from the operating In Salah project. CCS is expected to have applications in the oil and gas industry, and other industries, particularly the coal and power sectors. CO 2 -enhanced oil recovery, depleted oil and gas fields and saline formations are considered the most important geological storage options. Experience with geological storage is being gained at the In Salah project in Algeria. Operating since 2004, it is the world's first industrial-scale project storing CO 2 in the water leg of a gas reservoir. A key challenge for wider deployment is for geological storage to be accepted as a safe and effective option, providing long-term CO 2 containment, with high integrity. This has several associated technical and regulatory challenges, including site characterization and selection, geological and well integrity risk assessment, performance prediction, the design of appropriate monitoring schemes and handling the closure and post-closure phases. The petroleum industry has the capabilities and know-how to deploy CCS and to manage the associated risks. This lends confidence that CCS will be a viable option and that deployment will help enable a low-carbon future.

Reservoir compartmentalization: get it before it gets you

Abstract This paper examines the impact of compartmentalization on oil recovery, the importance of identifying it during field appraisal, and methods to evaluate it using fluid data. The impact on recovery factor is highlighted using a global database of oil field recovery factors as a function of reservoir complexity and compartmentalization, and emphasized in two case studies. The effect of compartmentalization on oil recovery demonstrates the benefit in characterizing compartmentalization correctly during appraisal, so that the field can be developed in an optimal manner. Early characterization of field compartmentalization requires making maximum use of available fluid data during appraisal. When interpreting fluid data to identify compartmentalization, it is critical to take into account the different time-scales for various fluid signals (pressure, contacts, density, composition) to equilibrate, and to be able to extrapolate to field production time-scales. This is essential to avoid false negatives (compartments assumed absent due to homogeneous fluid properties, when in fact fluids would have equilibrated even in the presence of compartments), false positives (where fluid differences are interpreted as evidence of compartments when in fact there has not been sufficient time for equilibration to occur), and to resolve apparently conflicting data (some fluid indicators are at equilibrium, others are not). Rigorous simulation of fluid equilibration is a complex multiphase multidimensional process, and is generally reserved for specialist in-depth studies. However, order-of-magnitude evaluations can be made using analytical solutions in minutes, allowing many ‘what-if’ scenarios to be considered and uncertainty to be assessed. Analytical solutions for estimating the time required for spatially-varying fluid properties to revert to steady state distributions are reviewed. All these mixing processes are shown to be diffusive in character. An effective diffusion coefficient for each process can be calculated from the reservoir rock and fluid properties. For an isothermal system, the different time-scales and distances for each fluid‐property variation to attain equilibrium can be compared on a single graph. Where the time elapsed since fluid‐perturbation is known, analytical solutions can be used to estimate the degree of compartmentalization (e.g. permeability of barriers). These solutions lend themselves to the development of simple practical compartment-assessment tools for industry practitioners.

Reservoir Technical Limits: A Framework for Maximizing Recovery From Oil Fields

Summary The Reservoir Technical Limits (RTL™) approach described herein has proved highly effective at identifying those activities and technologies required to push oilfield recovery factors toward their maximum potential. It combines classical reservoir engineering approaches, together with knowledge of existing and novel recovery-enhancing technologies, to create a common framework for identifying specific actions to increase recovery factor. RTL is implemented in a structured workshop supported by a software toolkit. The RTL workshop involves the cross-disciplinary field team (in-depth field knowledge), external technical experts (challenge, cross-fertilization), and trained facilitation. The software toolkit encourages innovation in a structured and reproducible manner and documents the outcomes in a consistent format. The RTL conceptual framework represents a recovery factor as the product of four efficiency factors: (1) pore-scale displacement (microscopic efficiency of the recovery process); (2) drainage (connectedness to a producer); (3) sweep (movement of oil to producers within the drained volume); and (4) cut-offs (losses related to end of field life/access). RTL encourages identification of new "opportunities," specific activities or projects that, if implemented, increase one or more efficiency factor, and thus increase recovery relative to the current field Depletion Plan. New ideas are stimulated by comparing current efficiency values with the effects of successful prescreened activities from analogue fields. The identified opportunities are validated by benchmarking: (a) internally, comparing recovery factors derived from summing the opportunity volumes with recovery factors derived from the expected efficiency factor increments; and (b) externally, comparing with analogue fields. The result is a prioritized list of validated opportunities and an understanding of how each activity affects the reservoir to increase recovery. The opportunities (and any required new technologies) are valued in terms of the resultant incremental barrels. The RTL approach is a significant innovation, because it provides a systematic framework to: (a) identify new recovery-increasing activities across a portfolio of fields; (b) engender ownership of these activities by the individual field teams; and (c) identify the technology requirements to progress the opportunities. Now, having been implemented in more than 200 fields, this systematic approach has enabled opportunity descriptions/values and technology requirements to be compared consistently across all fields, thereby improving project prioritization and focusing corporate technology development and deployment onto the highest impact areas.

An extractive distillation technique for producing CO 2 enriched injection gas in enhanced oil recovery (EOR) fields

Sharp Separation of CO 2 (carbon dioxide) from CO 2-rich gases issuing from enhanced oil recovery (EOR) fields is investigated by different processing alternatives. A new extractive distillation technique without using an external solvent is introduced for debottlenecking of CO 2 separation problem encountered in cryogenic distillation units. The technique involves the addition of a portion of produced C 4 + (NGL) stream (natural gas liquid stream comprising iso-butane and heavier components) to the top section of a CO 2 stripper followed by C 2/C 3 (ethane and propane) stripping of recovered C 2 + (ethane and heavier components) stream. Detail description of the proposed technique for producing greater than 96% CO 2-rich injection gas without external solvent is presented. According to the proposed approach, high quality C 2/C 3 and C 4 + products with the corresponding purities of 89.6% and 99.6% suitable as feedstocks for gas and petrochemical processing units are also obtained. Sharp separation of CO 2 from recovered hydrocarbon mixtures by the proposed technique and recycling it to petroleum reservoirs is an important issue regarding the optimization of EOR processes and greenhouse gas emission control.

Microbial technology applications in wellbore stimulation and oil recovery enhancement: a review

The different microbial technologies to enhance oil recovery have not yet been proven for two main reasons. Firstly, most microbial enhanced oil recovery (MEOR) field trials lack structured research methodology. Secondly, it is difficult to interpret MEOR tests. In order to correlate qualitatively the effects on oil recovery with the nutrient injections, other variables should be kept constant for a long time which is hard. Correlating these quantitatively is far more difficult. Another challenge is to decide accurately on the mechanisms through which microbes are affecting the oil recovery. To achieve this, additional wells have to be drilled, brine and oil chemical analysis have to be performed and DNA analysis have to be conducted. So far, it is believed that field trials intended to increase volumetric efficiency have yielded mixed results, whereas those designed to reduce permeability through biomass production of microbes are simpler and have a higher chance of success. [Received: December 3, 2008; Accepted: April 10, 2009]

Study of the Law about Water-Cut Variation for the Fractured Metamorphic Reservoir of Buried Hill with Bottom Water

Aiming at the complex flowing environment including the buried hill of Metamorphite, the active bottom water and the fracture at Budate Reservoir within Beir Depression of the Hailar Basin, combining the laboratory studies and based on analysis of its drive mechanism, field wells’ parameters were used to analyze the effects of different conditions of the fractured metamorphic reservoir with bottom water on its law of wa-ter-cut variation and the waterflooding efficiency. The results show that for the Budate buried hill reservoir with bottom water, the gravity should be taken into consideration to determine reasonable perforation ratio and production pressure difference. And because of the acid sensitivity of the buried hill reservoir, application of proper clay stabilizer will enhance the field oil recovery to a satisfactory extent.

Arthur B. Metzner

Arthur B. Metzner