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.
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.
Shale gas reservoirs have become financially attractive upon more efficient utilization of technologies such as horizontal drilling and hydraulic fracturing. In order to better identify such reservoirs, estimate their production potential, as well as
device optimum drilling and fracturing strategies, a detailed understanding of the connection between gas shale macroscopic mechanical and petrophyscal properties and microstructure is highly valuable. Since a high fraction of both pores and grain
structures in gas shales are of nanometer sizes, this requires advanced experimental techniques beyond what has commonly been applied on more conventional coarsely grained reservoir rocks. We present a study of the Mancos outcrop shale where we combine results from state-of-the-art nano tomography with results from standard rock mechanical, petrophysical, and geochemical testing. In addition to providing the first detailed investigation of the Mancos shale on the nanometer pore scale, this multi-scale analysis contributes to bridging the gap between small- and large-scale gas shale descriptions - and to establish the role of nano tomography in relation to more standard rock testing procedures. Our study revealed that the Mancos shale is marginally mature (%Ro ~ 0.66-0.70), gas prone and has a total organic content of 1.0-1.3 wt%. It is observed that even if the porosity of the organic matter itself is very low, organics are found in or around all analyzed fractures and voids in the Mancos sample. Large fractures parallel to bedding are observed to be organic-rich, potentially enabling the soft organic material to serve as a preferential weak plane when the rock is subjected to mechanical stress. This may be reflected in the observed significant strength anisotropy of about 60% deduced from rock mechanical tests on the same material. It is also suggested that nano/microfractures influence the measured acoustic properties, which appear consistent with those of other organic rich shales. Thus, knowledge of the detailed nanostructure, especially the distribution of organic matter, its porosity and its interface towards other solid phases, may be beneficial when attempting to predict shale macroscopic mechanical and petrophysical properties. Knowing these simplifies the process of identification and characterization of shale gas prospects, aswell as the subsequent drilling and production.
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.
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.
The precipitation and deposition of paraffin wax during production, transportation and storage of crude oil are common problems encountered by the majority of oil producers around the world. During the last decade, the Barrackpore oilfield in Trinidad has reported wax deposition on nineteen (19) of its wells. This condition has been exacerbated due to the reduction of temperature, pressures and losses of gas which have allowed wax to separate from the crude oil, precipitate and deposit in the walls of tubings, thereby reducing their diameter and restricting the flow of oil through the system. The situation represented a serious problem for Petroleum Company of Trinidad & Tobago (Petrotrin), because it caused a reduction in the production levels and significant economic losses. This study was based on the necessity to find feasible solutions to minimize this problem. The research was focused to determine if there was influence of the resin/asphaltene ratio on wax deposition under laboratory conditions, to start an understanding process of the causative factors of these depositions. In addition, the influence of two (2) different wax inhibitors were studied for comparison, since it is understood they may behave as resins peptizing the asphaltene particles and keeping them in solution. To ensure the validity of this investigation, extensive bibliographical reviews were undertaken, followed by numerous laboratory tests such as SARA analysis, Cloud Point Tests and Wax Content Tests as methods to evaluate the crude oil and its behaviour under various conditions. The results showed that wax and asphaltene content are the controlling factors in the precipitation and depositions processes respectively.
Sayed, Mohammed Ali Ibrahim (Texas A&M University) | Zakaria, Ahmed Salah El Deen (Petroleum Engineering Texas AM University) | Nasr-El-Din, Hisham A. (Texas A&M University) | Holt, Stuart Peter (Akzo Nobel Surface Chemistry LLC) | Almalki, Hassan (Qatar Petroleum)
The main objective of well stimulation has been to create wormholes or fractures in order to bypass the damaged zone and enhance the permeability in the near-wellbore area. Regular HCl was the main stimulation fluid. However, at high temperatures, both reaction and corrosion rates become very high and regular HCl loses its advantages. There are many alternatives for regular HCl; emulsified acid is one of the available alternatives for regular HCl.
In the present work, an emulsified acid system was used formulated using a cationic surfactant. This system was tested using reservoir cores obtained from a carbonate reservoir. The core samples were analyzed using CAT scan to study the presences of vugs or channels, and to determine the presence of anhydrite. Small samples of the cores were analyzed using the SEM technique. A series of core flood tests were conducted using 15 wt% HCl emulsified acid systems formulated using 1.0 vol% emulsifier. The acid volume fraction was 0.7, and all experiments were performed at temperature of 220ºF. The acid injection rate ranged from 1.0 to 10 cm3/min. After acid treatment is accomplished, the cores were CAT scanned to study the number and distribution of wormholes. Samples of the effluent fluid were collected during the core flooding experiment. These collected samples were analyzed using the ICP, to determine the calcium and magnesium concentrations.
The CAT scan of the cores obtained from a carbonate reservoir showed a great heterogeneity. The static test for solubility of rocks in regular 15 wt% HCl, indicated that the rocks has a high solubility in acid and the need to use an effective retarded acid system. From the coreflood study, there is an optimum injection rate for an emulsified acid system when it was tested reservoir cores, and it was found to be in the range from 5 to 7 cm3/min. The emulsified acid system can be used effectively, with no face dissolution, at low and high injection rates. For high permeability cores, the final permeability enhancement (ratio of final to initial permeability) increased with increasing the injection rate.
Long-term cement sheath integrity is important to maintain wellbore stability and effective zonal isolation. Various factors influence cement sheath integrity, such as effective placement of cement, mechanical and thermal stresses, and interaction with corrosive gases. Corrosive gases are known to chemically attack Portland cement. However, the challenge is designing a cement system that can sustain CO2 and H2S attack.
Acid-gas-resistant systems are useful in various applications, including producers and CO2 injector wells. To understand how the cement sheath is affected by prolonged exposure to corrosive gases, detailed studies should be performed at different temperatures and pressure conditions.
This paper documents a resilient cement system that was exposed to CO2 and H2S gas environments for a period of three months. For comparison purposes, a neat cement system was used as a reference and tests were conducted at 194 (90°C) and 284°F (140°C). X-ray density profiles obtained using tomography techniques were used to analyze samples. The cement samples responded differently to CO2 and H2S environments. Formation of CaCO3 on exposure to CO2 was evident and was reflected in X-ray density profiles. Conversely, leaching of neat cement was observed on exposure to H2S gas. In both cases, the resilient cement system specially designed for the work described proved to be a better option when compared to neat cement because the destruction was less prominent in the former case.
The Netherlands is a mature hydrocarbon province. EBN, the Dutch state participant for hydrocarbon exploitation and exploration, has identified shale plays as one of the contributors to add reserves and to maintain production at the current level. The main source rock for the limited amount of oil accumulations in The Netherlands are the Lower Jurassic (Toarcian) oil-prone shales. Lower Carboniferous (Namurian) hot shales have often been suggested as possible contributor to oil and gas Formation in The Netherlands as well, but this has not been proven to date. Recent discoveries of gas in the time-equivalent Bowland shales in the UK have encouraged interest in the production potential of these shales in North-western Europe. In this paper the geological and geomechanical properties of the Lower Jurassic and Lower Carboniferous are presented in a shale play context. The assessment methodology is subdivided in three sections: 1) the overall geology of the play, 2) the type and quantification of hydrocarbons present and 3) the production characteristics. New and specific measurements
on core and cutting material include pyrolysis, methane adsorption, mineralogy, texture, porosity, permeability, static and dynamic geomechanical properties, hardness and fracture conductivity.
The two identified plays show very distinctive properties. The Lower Jurassic samples indicate to be mostly thermally immature for dry gas implying that liquids can be expected. The Lower Carboniferous samples show areas that are overcooked. Mineralogical and geomechanical data suggest that different stimulation strategies may be necessary for these two plays to produce hydrocarbons effectively. The source rocks of Lower Jurassic age qualify as relatively soft while the Lower Carboniferous shales with high TOC content classify as very hard. Comparing the results of the assessment to known shale plays in the US, the plays position themselves in the opposite extremes of the productive shale play spectrum.
The resource base of the Netherlands is maturing rapidly. The current portfolio of producing gas fields shows that approximately 75% have produced more than half of their initial reserves volume (EBN, 2010). In order to maintain the current high production levels, enhanced recovery from existing fields is required as well as portfolio rejuvenation by increased exploration activities. In North America the gas production from organic rich shales have proven to be a game changing concept for the gas industry. This success sparked a worldwide interest in other shale basins with similar characteristics. In order to assess the
production potential of this type of unconventional resource, The Netherlands are currently investigating their prospective shale resources.