Recent work has shown the potential usefulness of both magnetic susceptibility and magnetic hysteresis techniques in assessing the effect of fine-grained hematite on permeability, where the hematite was dispersed in the matrix of relatively tight gas red sandstone samples. The present study demonstrates that grain lining hematite cement is also a major controlling factor on permeability in a relatively tight gas sandstone reservoir in the North Sea. Magnetic susceptibility measurements on core plugs in this reservoir showed a strong correlation with probe permeability. Moreover, samples with a higher content of hematite exhibited lower permeability values. Thin-section analysis revealed the presence of a thin (approximately 10 to 15 lm) rim of hematite cement surrounding quartz grains, which block pore connections and reduce permeability. Magnetic hysteresis measurements on representative samples indicated a similar paramagnetic clay content in both the low and high permeability samples, suggesting that the clay (mainly illite) is not the dominant controlling factor that produces the variations in permeability that we observed. Because samples with higher hematite content exhibit lower permeability, it appears that hematite is a major control on the permeability variations seen in this reservoir. Although the paramagnetic clays undoubtedly have an influence on the absolute permeability values (increasing paramagnetic clay content has previously been shown to correlate with decreasing permeability), small amounts of grain lining hematite cement can reduce the permeability significantly further. Analysis of the magnetic hysteresis parameters on a Day plot indicated that the permeability was essentially independent of the hematite particle size for the fine particle sizes observed in this study.
Waterflooding has been the most popular post-primary production approach for improving oil recovery. In fractured reservoirs with large structural relief, gas injection can produce much of the post-waterflood remaining oil by gravity drainage. Oil recovery by gas-invoked gravity drainage in waterflooded reservoirs is known as the double displacement process (DDP). One major reason, among many, is that the three-phase relative permeability residual oil saturation endpoint is generally smaller than the residual oil saturation endpoint for the water-oil displacement.
Field data indicate that the DDP has been successful in single-porosity sandstone formations. Intuitively, one can expect that DDP should produce similar results in reservoirs with ample intercommoned vertical fractures, which is the objective of this work. With the aid of tests on tight reservoir cores from a major Middle East carbonate reservoir, this study focuses on evaluating the DDP in fractured carbonate reservoirs where the wettability ranges from neutral to oil-wet conditions. The scope of the study includes: (1) assessment of the DDP experimentally in fractured cores using a high-speed centrifuge, (2) simulating the experiments numerically, and (3) upscaling laboratory results to field applications.
Results from water-oil gravity drainage tests followed by gas-oil gravity drainage in fractured and unfractured cores are presented. We also show numerical simulation results of matching the experiments using both transfer function and 2-D numerical simulation, and how results from our study can be used in field applications.
Typical waterflood oil recovery from 0.1-md to 2-md fractured carbonate cores has been noted to be around 38% of the initial oil in place while incremental additional oil recovery for gas-oil gravity drainage is nearly as much as the recovery from water.
Rock mechanics tests on core from Early Cretaceous carbonate reservoirs from a super-giant field offshore Abu Dhabi has allowed definition of rock mechanical facies (RMF). Each of four RMF are based on stress-strain curves and associated strength and elastic parameters. The lab-based RMF correlate with mechanical stratigraphy classes previously defined from core (and that reflect visible differences in lithology and cementation). The RMF are correlated to reservoir zones and inter-reservoir, impermeable dense intervals, with three facies predominantly correlating with reservoir lithologies and one corresponding with primarily dense intervals. However, some reservoir zones, or sub-zones, can lie in more than one RMF. The RMF are, therefore, partly predictable: for any reservoir zone in the field prediction accuracy is to one or one of two RMF classes. This ambiguity is due to two factors: (i) lateral variation of RMF within some reservoir zones based on lithofacies; and (ii) continuity of mechanical properties between RMF classes. There is a change in RMF from crest to flank of the reservoir, as expected, but there is also local lateral variation within the crest of the field. The two RMF representing most of the reservoirs are expected to respond differently to field operations. Therefore, mapping lateral variation of RMF for some reservoir zones may provide a basis for implementing different reservoir management practices in different areas/zones of the field. The ultimate use of this information will be to enable full-field rock mechanics simulation of the reservoir to help understand the long-term effects of different production strategies.
Introduction & Background
The concept of mechanical stratigraphy is widely used, commonly to correlate fracture distribution and intensity to stratigraphy. The concept of rock mechanical facies (RMF) whereby a number of measured rock mechanical properties are correlated to stratigraphy is not new and is referred to in a number of papers, for example: Alhilali & Shanmugam (1991); Corbett & Friedman (1987); Yale & Jamieson (1994); McDermott et al., (2006); Khaksar, et al. (2009). However, RMF do not seem to be commonly used as a concept. We believe that characterising formations in terms of RMF has the potential to simplify characterisation for use for drilling; reservoir management; and history matching for simulation. In this paper we will describe how we have defined RMF for an oil-field and will discuss one way in which RMF could be used in the field.
The studied oil-field comprises a stack of limestone reservoirs separated by impermeable "dense?? limestone layers of Early Cretaceous age in a giant field located offshore Abu Dhabi (Figures 1 & 2). Production in the field has been by variably patterned water-flood over the last 30+ years. The dense layers measure up to a few tens of feet in thickness; the main reservoirs are up to 150 ft. The reservoirs are typically characterized by moderate to low matrix permeability, generally, but not exclusively, from 50 mD to 2 mD. Porosity is mostly in the range of 15-25%, more than half of which is microporosity. Depositional textures are predominatly wacke- to packstone with high-permeability streaks due to rudist and algal floatstone to rudstone and grainstones. Although intense bioturbation has destroyed most of the depositional textures, heterogeneities remain in some reservoirs in the form of dolomite-filled burrows, patchy/nodular cementation, stylolites and wispy solution seams, and fractures; all can occur as different layers within the reservoir. The reservoirs are not highly fractured although diffuse fractures are concentrated at the top and base of most reservoirs.
NMR relaxation measurements are routinely used in the petroleum industry to estimate permeability and to partition fluids to estimate irreducible water saturation. The shape of the relaxation time distribution is controlled by many mechanisms like pore-coupling in the presence of heterogeneity, internal gradient effects, and signal to noise ratio. However, given an anchoring of the relaxation time distribution, the logarithmic average of the NMR T2 distribution is a relatively robust measure and for rocks where a correlation between pore and throat size exist, a reliable estimate of permeability can often be made. In this work we utilize high resolution X-ray CT images Berea and Bentheimer sandstone and simulate the NMR relaxation-diffusion responses for the case of drainage by a non-wetting fluid at different magnetic field strength (2MHz, 12 MHz, and 400 MHz), calculating internal magnetic fields explicitely. The T2-D responses are projected onto the relaxation axis for each fluid and the SDR model used to predict absolute and relative permeabilities. The resulting correlations between NMR response and relative permeability are surprisingly strong. In particular, reasonable correlations exist between lattice Boltzmann derived relative permeability and NMR estimated relative permeability even for the effective permeability of the oil. This suggests that internal fields help in establishing a surface related/weighted relaxation mechanism for the non-wetting fluid. This methodology allows testing the applicability of SDR type relative permeability estimates for the purpose of log analysis. A variety of cross-correlations including resistivity information can be considered and correlations between relative permeability and NMR response are optimized by finding the best NMR acquisition sequence and interpretation (e.g. choosing optimal cut-offs).
This article, written by Editorial Manager Adam Wilson, contains highlights of paper SPE 142592, "Industry First Field Trial of Reservoir Nanoagents," by Mazen Y. Kanj, SPE, Saudi Aramco, and M. Harunar Rashid and Emmanuel P. Giannelis, Cornell University, prepared for the 2011 SPE Middle East Oil and Gas Show and Conference, Manama, Bahrain, 25-28 September. The paper has not been peer reviewed.
Cementing a string in one stage is a challenging task, especially in the presence of weak formations. Cement slurry losses during placement is highly possible if the equivalent circulating density (ECD) exceeds 82 pcf during placement. A conventional method to overcome this challenge is to use multi-stage cementing by setting the stage tool above the loss circulation zone. However, field data indicate that the tool can fail, thus causing serious delay and economic loss. In addition, stage tools are considered weak point and not good for long term seal. A second method for zonal isolation is to use low density cement.
In this study, we present extensive lab evaluation of a low density system based on the use of hollow microspheres for one year at field conditions. The tests included one year mechanical properties measurement such as compressive strength development, Young's modulus and Poisson's ratio. The low-density system (70 pcf) was tested at 300 ºF. An earlier study has shown the suitability of using low density cement in the field, Al-Yami et al. (2007). However, there is no available
Investigation in the literature about the durability of low density cement at higher temperature and at different operational scenarios.
The finite element method was used to analyze the failure probability of HPHT wells over with time. At the variation of bottom whole pressure, the casing, cement, and formation system failure probability was studied for this type of cement.
This paper introduces the operational envelope for this type of cement in order to achieve successful operations. Field cases were discussed to validate the results of this investigation.
Daungkaew, Saifon (Schlumberger) | Fujisawa, Go (Schlumberger) | Chokthanyawat, Suchart (Schlumberger) | Ludwig, John Thomas (Chulalongkorn University) | Houtzager, Johan Frederik (Pearl Oil Thailand Ltd) | Platt, Christopher J. (Pearl Oil Thailand Ltd) | Last, Nick (Pearl Oil Thailand Ltd) | Comrie-Smith, Nick (Salamander Energy)
Accurate viscosity measurement is difficult even under the best of conditions and the lengthy time required to send and receive results from a lab prohibit basing important decisions on the viscosity of the reservoir fluid. Those challenges increase for reservoirs with complex fluids such as the highly viscous, waxy crudes found in many of the oil fields in South East Asia.
While correlations have been developed to determine the viscosity of waxy crudes, the accuracy can be limited under certain conditions. The objective of the paper is to review viscosity correlations for waxy crude and examine their applications to the actual field data. Limitations on the use and accuracy of these correlations will then be discussed. This paper also discusses the viscosity obtained in real-time from the suite of Downhole Fluid Analysis (DFA) measurements, and the result is then compared to standard PVT analysis over a wide range of viscosities, temperatures, and pressures.
Results of the DFA viscosity measurements in several fields in South East Asia are discussed together with other fluid properties such as GOR, density, and fluid compositions. The viscosity is then examined at the field scale to help understand the reservoir complexity in terms of compartmentalization in these waxy oil environments.
The technical contribution from this paper is that it presents the variation of the viscosity in waxy oil reservoirs and its impact on real time decision making, especially for purposes of pressure transient analysis. This paper covers the evolution of the DFA viscosity measurement including a description of the hardware, discusses the limitation of the DFA measurement for certain conditions, and summarizes the accuracy of the DFA viscosity measurement for different fluids and the ongoing development for covering more fluids in the lower end of the viscosity spectrum.
Salym Petroleum Development (SPD) oil company is a joint venture between Shell and JSC Gazprom Neft. SPD currently holds three license areas in the south of Khanty-Mansiysk Autonomous Okrug. So far the company has concentrated its efforts on further exploration and development of ‘traditional deposits': from early production at the Upper Salym filed to commissioning state-of-the-art central oil production facility at the large West Salym field and the satellite Vadelyp field.
At the early stage of field development the company started to research ‘non-traditional' hydrocarbon resources. One group of these resources is immobile oil remaining in flooded reservoir after the waterflood target oil recovery factor had been achieved; another group of resources is Bazhenov Formation oil. These resources are not currently developed actively because of the combination of technological risks and current macroeconomic conditions in Russia. However, the study of analogous fields shows that the industry practice has successful solutions for both groups of the problems and non-traditional resources with the characteristics presented at the Salym group of oil fields are in fact successfully developed elsewhere (after elimination of technical risks through analytic work and field tests).
The work on the enhanced oil recovery project began with the high-level assessment of various technologies in 2007. In 2010 a more detailed study of potential technologies was carried out including high pressure air injection and low salinity waterflooding.
As a result of screening an EOR method of flooding with the solution of chemicals - Alkaline-Surfactant-Polymer - was chosen. Initial stages of the project comprised lab tests, core experiments and field tests. From these tests, an estimate of potential oil recovery factor increase of 15 %-20% (of STOIIP) was confirmed. In 2011 the ASP project reached maturity when the next stage would be implementation of the pilot project activities. Currently the work is on the way to design the flooding pattern and surface processing facilities with expected ASP oil production in 2014-2015.
In the beginning the article gives a short overview of the history and status of the project. After that it describes the stages of analytical work in Russian laboratories to find, optimize and test various types of Russian surfactants. This work was carried out under the guidance of the operator (Salym Petroleum) with the engagement of specialists from Shell and Gazprom Neft research centres. As a result lab samples of anionic surfactant showed satisfactory results during core flood experiments.
Finally it is worth mentioning that one of the results of the work was the establishment of methodological and experimental framework on the basis of Russian contractors and laboratories which made it possible to asses, within the short period of time, a large number of chemicals used on the Russian market for EOR activities.
The increasing complexity of collectors developed makes new demands on geological samples investigation methods. A breakthrough in high-performance calculations for multi-physical processesmade it possible to perform digital core analysis based on microanalysis and X-ray computed tomography allowing the study of the volume distribution of density inhomogeneties, physico-chemical and petrophysical properties of rocks. Data obtained by such methods can be used for quality control, laboratory research optimization, reservoir properties description of formation based on sludge and unconsolidated cores, characterization of cracks, cavities, the matrix porosity, distribution of salts in carbonates of Eastern Siberia, upscaling core - layer. As a result, companies in the industry can get the potential effect of the introduction of digital technology in the form of faster decision-making, refining the project design and economic model in the design of field development.
Burnett, David B. (Texas A&M University) | Vavra, Carl (Texas A&M University) | Platt, Frank Martin (Texas A&M University) | Mcleroy, Lowell Keith (Texas Engineering Extension Services-Water) | Wood, Robert (Texas A&M University)
Shale gas development relies heavily on multi-stage hydraulic fracturing to maximize the economic viability of each new well. In recent years, the industry is aiming at re-use of frac flow back brine to reduce costs and environmental impact of operations. The challenge is to identify technologies and approaches for treating the frac water that returns to the surface following a frac job (frac flowback water) for beneficial re-use in other applications, thereby conserving other local freshwater supplies. Field trials in upstate New York have been conducted to test new technology to treat brines characteristic of flow back brines from the Marcellus Shale and make them amenable for re-use in subsequent oil field operations.
The Texas A&M GPRI produced water treatment program began in the year 2000. In the past decade we have shown that produced water and frac flowback brine from shale gas and tight gas well drilling operations can be treated and reused instead of tapping in to additional fresh water resources. Now the program is working to demonstrate that low cost, mobile units can be deployed in field operations to replace the more costly and environmentally questionable practices currently being employed in field operations.
This report describes the field trial in Chenango County New York conducted by the Texas A&M Desalination Program during the 3th quarter of the year 2011. The specific goal of the field trial was to develop and utilize a mobile unit to demonstrate the effectiveness of different membrane technology suitable for use with high salinity flow back brines and produced water from the Herkimer formation the brines deemed the equivalent of Marcellus Shale brine.
The several treatment techniques which have been found to be successful in both pilot plant and field tests have been tested to incorporate into a single multifunctional process train. Eight different components were evaluated during the trials, two types of oil and grease removal, one BTEX removal step, three micro-filters, and two different nanofilters. The performance of each technique was measured by its separation efficiency, power consumption, and ability to withstand fouling overall, the field trial was a success. Of the four field brines evaluated, three were treated with minimal problem. Over 6,000 gallons of brine were processed. Total power cost was approximately $1.00 per barrel of fluid treated.
Managing produced water and frac flowback brines from petroleum operations represent a significant expense to companies developing new energy reserves.