Cinar, Yildiray (The University of New South Wales) | Arns, Christoph (The University of New South Wales) | Dehghan Khalili, Ahmad (The University of New South Wales) | Yanici, Sefer (The University of New South Wales)
Resistivity measurements play a key role in hydrocarbon in place calculations for oil and gas reservoirs. They are a direct indi-cator of fluid saturation and connected pore space available in the formation. Carbonate rocks, which host around half of the world's hydrocarbons, exhibit a wide range of porosities with scales spanning from nanometres to centimetres. The often sig-nificant amount of microporosity displayed by Carbonate rocks emphasizes the necessity of an adequate characterization of their micro-features and their contribution to hydrocarbon in place. In this paper we examine upscaling methods to probe for-mation factor of a fully saturated carbonate sample using an X-ray CT based numerical approach and compare to experimental measurements.
Three-dimensional high-resolution X-ray CT enables the numerical calculation of petrophysical properties of interest at the pore scale with resolutions down to a few microns per voxel. For more complex and heterogeneous samples however, a direct calculation of petrophysical properties is not feasible, since the required resolution and a sufficient field of view cannot be obtained simultaneously. Thus an integration of measurements at different scale is required. In this study a carbonate sample of 38mm in diameter is first scanned using the X-ray CT method with a resolution of 26µm. After accompanying experimental measurements on the full plug, four 5mm plugs were drilled vertically from this sample and X-ray CT images of these plugs acquired at resolutions down to 2.74 µm. We calculate the porosity of the sample (macro- and micro-porosities) using the phase separation methods and then predict the formation factor of the sample at several scales using a Laplace solver. The formation factor is calculated by using a general value of m=2 as cementation factor for intermediate porosity voxels. We compare to experimental measurements of formation factor and porosity both at the small plug and full plug scale and find good agreement.
To assess the degree of uncertainty of the numerical estimate, we probe the extent of heterogeneity by investigating the size of a representative elementary volume (REV) for formation factor. We find that for the considered heterogeneous carbonate sam-ple, formation factor varies considerably over intervals less than a centimetre. Our results show that this variation could be explained by different cementation exponents applied at the micro-voxel scale, with the exemption of one plug, for which the cementation exponent would have to be unreasonably low. These cementation factors are derived by direct comparison be-tween numerical simulation and experiment. We conclude that for one plug an error in experimental measurement might have occurred. The numerical approach presented here therefore aids in quality control. Excluding this plug in the upscaling proce-dure improves the agreement with the experimental result for the whole core while still underestimating formation factor. Al-lowing for a constant m=2 in the simulation at the small scale and using directly the resulting relationship between porosity and formation factor in the upscaling process leads to an overestimation of formation factor.
Telang, Milan (Kuwait Oil Company) | Al-Matrook, Mohammad F. (Kuwait Institute for Scientific Research) | Oskui, Gh. Reza (Kuwait Institute for Scientific Research) | Mali, Prasanna (Kuwait Oil Company) | Al-Jasmi, Ahmad (Kuwait Oil Company) | Rashed, Abeer M. (Kuwait Institute for Scientific Research) | Ghloum, Ebtisam Folad (Kuwait Institute for Scientific Research)
Asphaltene deposition problems in Kuwait have become a serious issue in a number of reservoirs during primary production in different fields, resulting in a severe detrimental effect on the economics of oil recovery. Hence, one of the mitigation approaches in the field is using remedial solvent treatments, such as Xylene or Toluene, which is very costly and harmful to the environment.
Kuwait Oil Company (KOC) is planning to produce from asphaltinic Marrat wells that have been shut down due to low bottom-hole pressure (BHP), by artificial lifting technique using an Electric Submersible Pump (ESP) supported with continuous chemical injection, as a pilot. The main objective of this study was to investigate in the lab the effectiveness of various concentrations of toluene/diesel (T/D) mixtures on Marrat reservoir fluid in order to mitigate asphaltene deposition problem during the actual pilot implementation.
Preliminary screening tests were conducted on the surface oil sample using Solid Detection System (SDS) "laser technique?? to determine the optimum dose of the T/D mixture ratio. The results showed that pure diesel accelerated the asphaltene precipitation; however, mixing T/D inhibited the precipitation process. Series of pressure depletion tests was then conducted on live oil , single phase samples, to determine the Asphaltene Onset Pressure (AOP) with and without adding various ration of T/D solvents at different temperatures from reservoir to surface conditions.
The results revealed that using 15% (by volume of oil) from the (50T:50D) mixture reduced the AOP close to the bubble point pressure. Furthermore, the amount of the precipitated asphaltene was physically quantified using a bulk filtration technique. It was observed that, based on blank sample, the wt% of the precipitated asphaltene was minimized at the AOP and maximized at the bubble point. However, using the recommended mixture of 50T/50D, the amount of asphaltene that precipitated was almost negligible. Therefore, from a health, safety, and economic point of view, this study recommends using a low dose of 7.5% (by volume of oil) from toluene mixture with diesel (50%:50%) rather than using pure toluene to prevent the precipitation.
Permeability provides a measure of the ability of a porous medium to transmit fluid and is significant in evaluating reservoir productivity. A case study that compares different methods of permeability prediction in a complex carbonate reservoir is presented in this paper. Presence of siliciclastic fines and diagenetic minerals (e.g., dolomite) within carbonate breccias has resulted in a tight and heterogeneous carbonate reservoir in this case. Permeability estimations from different methods are discussed and compared. In the first part of the paper, permeability measurements from conventional core analysis (CCAL), mercury-injection capillary pressure (MICP) tests, modular formation dynamic tests (MDTs), and nuclear-magnetic-resonance (NMR) logs are discussed. Different combinations of methods can be helpful in permeability calculation, but depending on the nature and scale of each method, permeability assessment in heterogeneous reservoirs is a considerable challenge. Among these methods, the NMR log provides the most continuous permeability prediction. In the second part of the paper, the measured individual permeabilities are combined and calibrated with the NMR-derived permeability. The conventional NMR-based free-fluid (Timur-Coates) model is used to compute the permeability. The NMRestimated permeability is influenced by wettability effects, presence of isolated pores, and residual oil in the invaded zone. new modified Timur-Coates model is established on the basis of fluid saturations and isolated pore volumes (PV) of the rock. This model yields a reasonable correlation with the scaled core-derived permeabilities. However, because of the reservoir heterogeneity, particularly in the brecciated intervals, discrepancies between the core data and the modified permeability model are expected.
Acharya, Mihir Narayan (Kuwait Oil Company) | Kabir, Mir Md Rezaul (Kuwait Oil Company) | Al-Ajmi, Saad Abdulrahman Hassan (Kuwait Oil Company) | Pradhan, San Prasad (Kuwait Oil Company) | Dashti, Qasem M. (Kuwait Oil Company) | Al-anzi, Ealian H.D. (Kuwait Oil Company) | Chakravorty, Sandeep (Schlumberger)
The deep, sub-salt reservoir complex is tiered with fractured tight carbonate at bottom and top, with the two sub-units of "upper unconventional kerogen?? and "lower inter-bedded kerogen-carbonate?? in the middle. This depositional setting is challenging for horizontal well placement where the thicknesses of respective sub-units are about 50 and 30 feet with varying geomechanical and petrophysical properties. Additionally, this complexity poses limitations in completions and effective stimulation of the Kimmeridgian-Oxfordian reservoirs in several gas fields at development stage in Kuwait.
A horizontal well is placed in the lower sub-unit of the laminated complex of unconventional kerogen and fractured carbonate reservoir as a Maximum Reservoir Contact (MRC) type well. A pilot mother-bore was drilled and logged to identify the lithological properties across the entire vertical domain - facilitates the optimization of horizontal drain-hole placement within the targeted reservoir units.
No wellbore stability issues in drilling were predicted based on the geomechanical understanding where core-calibrated logs from offset vertical wells were considered. However, this modeling method did not have the functionality to integrate the impact of drawdown on the laminated formation which became unstable and collapsed during the short open-hole drill-stem test (DST) plugging the tubing prior to the final completions. An alternative "book-shelf?? geomechanical model was considered at pre-drill stage for predicting the wellbore stability. Once the drilling was completed, the time-lapsed multi-arm caliper indicated the validity of the alternative methodology in predicting the unstable stack of laminations in kerogen-rich strata.
The paper discusses an optimization methodology to enhance the understanding of static and dynamic geomechanical stability through the use of BHI data. Objective of the proposed method is to help improve the effectiveness of completions where wellbore stability due to geomechanical complexity in stacked-pay reservoirs is a primary wellbore challenge in deploying the completions and executing a subsequent stimulation and testing campaign.
Proper characterization of reservoir quality of tight shales is critical for evaluating reservoir potential. These reservoir quality properties typically include hydrocarbon filled porosity, permeability, organic content and maturation, and pore pressure. Of these, permeability measurements are among the most complex to obtain, and have been subject to much discussion. Key concerns are the lack of analytic modeling, poor reliability, poor consistency, and ignoring stress sensitivity in the measurements. This paper reviews the pressure decay permeability method using crushed rock, and includes laboratory test results to validate the findings. Part of the review is a numerical model for the pressure decay method. This model includes significant processes of pipe flow in the equipment, thermal effects, diffusion into rock fragments, Klinkenberg effects, and size, shape and anisotropic permeability of the fragments.
The paper shows that the measured permeability stress dependence, in tight shales, arises from coring induced microcracks. These result from failure of weak contact planes that are naturally occurring within tight shales and fail during coring and core retrieval. Permeability stress dependence in-situ is slight, as is show by compression test measurements to greater than thirty thousand psi. Crushing the rock to create small fragments for permeability measurements effectively removes these microcracks, and allows evaluation of real in-situ properties. Alternatively, closing microcracks by applying confining stress on plug samples, as routinely done for steady state and pulse decay measurements, is possible, but problematic because the critical stress required for microcrack closure changes from rock to rock facies.
The pressure decay permeability method on crushed rock is shown to provide very consistent results that agree with other measurement techniques. The numerical model relates specific ranges of fragment sizes and testing conditions, to measured ranges of permeability. This allows permeability measurements and numerical model analysis for a broad range of variability in permeability that can be measured in heterogeneous tight shales. With some exceptions (e.g., Cui et.al. 2009), the fundamental understanding of the petrophysical properties of tight shales have not previously included rigorous confirmation of experimental measurements by analytical methods.
Fracture fluid flow back has been identified as one of the major challenges of hydraulic fracturing operations conducted in shale reservoirs. Factors causing the very low fracture fluid recovery need to be well understood and properly addressed, in
order to get full benefits from costly hydraulic fracture jobs conducted in unconventional reservoirs. Despite the recent surge of investigations of the problem, one major question still remains: what happens to the fracture fluid that is not recovered?
Does it stay in the fracture or does it go into the matrix? In case of both mechanisms are responsible for fracture fluid retainment, what fraction of fracture fluid stays in the propped fracture and what fraction is transferred from fracture to
matrix. The focus of the current study is to understand if the transfer of fracture fluid from fracture to matrix through imbibition is of significant importance.
We systematically measure the imbibition rate of water, brine, and oil into the actual core samples from the three shale sections of Horn River basin (i.e., Fort Simpson, Muskwa and Otter Park). We characterize the shale samples by measuring,
porosity, wettability, mineral composition through XRD analysis, and interpreting the well log data. The results show that imbibition could be a viable mechanism for fluid transfer from fracture to matrix in Horn River shales. The comparative study shows the imbibition rate in the direction parallel to the bedding plane is higher than that in the direction perpendicular to the bedding. The study also suggests that the imbibition rate of the aqueous phases is significantly
higher than that of the oleic phases.
It is found that in the deepest part of Cooper Basin (Permian section in Nappamerri Trough) in South Australia, two shale formations, Roseneath and Murteree have potential to be shale gas reservoirs. However, a comprehensive petrophysical evaluation has not been carried out so far. The free porosity among minerals, pore throat geometry, surface area and structure of micro pores for adsorption and diffusion of gas in these formations have not been well understood.
Two core samples from two wells (Della 4 and Moomba 46) were selected to evaluate mineralogy, free porosity and other petrophysical characterization. Since routine core analysis is not capable of petrophysical characterization of these very tight rocks, the latest technology of image scanning and processing of QEMSCAN (Quantitative Evaluation of Minerals using Scanning Electron Microscopy) and Computerized Tomography (CT) scanning have been used. QEMSCAN is a novel technology to process images from electron microscope to measure size and distribution of different minerals in a rock sample. QEMSCAN when combined with CT scanning can significantly enhance shale rock characterization and reservoir quality assessment. In this study, the main goal is the evaluation of total free porosity, micro pores and natural network of micro-fracture systems in our ultra fine samples.
Based on QEMSCAN analysis, it is found that the sample of Murteree shale has the mineralogy of quartz 42.78%, siderite 6.75%, illite 28.96%, koalinite 14.09%, Total Organic Content (TOC) 1.91 wt%, and pyrite 0.04%, while rutile and other silicates minerals were identified as accessory minerals. Total free porosity is found to be 2 percent. The free porosity is largely associated with clay minerals which shows intergranular linear, isolated and elongated wedge shaped pores. SEM images from the same core sample also show that the pores are mainly present in clay rich zone. QEMSCAN maps have revealed the location of lamination, high and low porosity zones as well as high and low sorption areas. In CT scanning, the porosity found in QEMSCAN, was not identified; however, a network of micro-fracture system in Murteree shale sample is identified.
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 E Field, with depletion type reservoirs offshore Sabah, started first production in the early 1980's with no active sand control measures where all the wells, many of which were horizontal, were completed as cased hole and perforated. After some 25 years, most wells began to produce sand along with high gas production, causing supply curtailment with some wells requiring shut ins. A new development plan executed in August 2010 involved drilling five new wells from an existing platform to include active sand control as part of the overall strategy. Due to the costly gravel packing operation coupled with the potential high skin in such completion, a new sand control approach was adopted. The key to this approach was to limit the production drawdown to a certain level by maximizing the well productivity index (PI) through open hole completion and to avoid sand influx at the early stage. Stand alone screen (SAS) completion consisting of a selected screen of a specific slot size was installed in the open hole, acting as a second production barrier in the event sand influx occurs.
The geomechanic study on E field data suggested that with ongoing depletion, the new wells would exceed the critical drawdown pressure (CDP) and sand production is expected from day one as evident from sand production issues in the field. However, it was decided to test the limit of this study with consideration relying more on the inherent strength of the rock as reflected by the high unconfined compressive strength (UCS) data of over 5000psi and thus the wells were completed with SAS in open hole. Permanent downhole gauges (PDGs) were installed in all the SAS wells to monitor the production drawdown closely, especially during the initial production phase.
The target reservoir is semi-consolidated laminated sandstone with poorly sorted sand of uniformity coefficient (UC) value of over 15 and d10 finer size sand content of over 10%. Based on retention test results, the 175µm screen size was chosen as using the d10 particle size (92µm) option will likely result in excessive plugging during the projected sand failure phase. This alternative selection is effectively moving beyond the currently accepted screen selection criteria limits.
This paper highlights design considerations in E field aimed at optimising well productivity and reducing sand control cost by challenging current standards and limits commonly adopted in sand control completions. The well performance results following the revisit are also reviewed to support this unconventional approach. This is expected to contribute to the evolution of future sand control strategies. Lessons learnt during well cleanup and initial production phase with continuous monitoring from downhole PDGs are included to provide a holistic picture of this case study.
The increasing attention and development of unconventional resources has many in the industry searching for suitable analogs to supplement their evaluation. A common approach is the use of type wells. Type wells are created by averaging the rate of several analogous wells. This type well rate and corresponding volume is used as a benchmark for evaluating and guiding forecasts for similar wells. The concept of type wells is not new but there are aspects that can be refined to improve results.
The current industry practice has a flaw that when combined with development practices will provide inaccurate results. When creating a type well from historical data only, forecasts are implicitly calculated for wells that do not have enough production to reach the end of the type well time interval. Adding to this is the fact that operators will optimize profit by drilling their best wells first. In this instance the type wells will have a greater rate profile and expected ultimate recovery (EUR) than the underlying data will support. This is because the implicit forecasts for the newer, less productive wells are created from the older, better wells. Conversely, type wells will under-predict rate and EUR in technical plays where performance improves with experience. This paper proposes an approach to address the flaw.
When historical production data is merged with reliable production forecasts to build a type well, the resulting type well is the best available representation of the underlying data. Measures to ensure accurate forecasts on individual wells are recommended.
As an extension to predicting a single rate for similar wells, type wells are also employed to predict different percentile outcomes for similar wells. A common method considers all of the data and calculates a percentile at each time step (Time Slice approach). This approach does not produce consistently reliable results. This paper will propose an alternative approach to creating Type Wells at varying percentiles by analyzing actual wells whose outcome is close in value to the desired percentile.