Timely and detailed evaluation of in-situ hydrocarbon flow properties such as oil density and viscosity is critical for successful development of heavy oil reservoirs. The prediction of fluid properties requires comprehensive integration of advanced downhole measurements such as nuclear magnetic resonance (NMR) logging, formation pressure, and mobility measurements, as well as fluid sampling.
The reservoir rock presented in this paper is an unconsolidated Miocene formation comprising complex lithologies including clastics and carbonates. The reservoir fluids are hydrocarbons with significant spatial variations in viscosity ranging from (60-300 cP) to fully solid (tar). Well testing and downhole fluid sampling in this formation are hindered by low oil mobility, unconsolidated formation that generates sand production, emulsion generation, and very low formation pressure.
We present a two-pronged log evaluation workflow to identify sweet spots and to predict fluid properties within the zones of interest. First, the presence of "missing NMR porosity" and "excess bound fluid" is estimated by comparing the NMR total and bound fluid porosity with the conventional total porosity and uninvaded water-filled porosity logs, respectively. Secondly, two-dimensional NMR diffusivity vs. T2 NMR analysis is performed in prospective zones where lighter and, possibly, producible hydrocarbons are detected. The separation of oil and water signals provides a resistivity-independent estimation of the shallow water saturation. Additionally, we correlated the position of the NMR oil signal with oil-sample viscosity values. The readily available log-based viscosity greatly improves the efficiency of the formation and well-testing job.
We successfully sampled high viscosity hydrocarbon fluids by utilizing either oval pad or straddle packer. The customized tool designed for sampling aided gravitational segregation of clean hydrocarbons from the water-based mud filtrate and emulsion; and therefore providing representative reservoir fluid samples based on downhole fluid analyzers.
Development of source-rock resources relies on the rigorous knowledge of their petrophysical properties such as porosity, permeability, and hydrocarbon saturation. In parallel, a concise description of the wettability and pore structures is commended. This paper presents a detailed Nuclear Magnetic Resonance (NMR) T2 study of the wetting characteristics and pore structure in organic-rich source rocks from different locations including the Eagle Ford formation. Although these rocks are highly laminated and calcite dominated, our studies indicated that they have distinct different pore structure and connectivity, and differ in how TOC is dispersed within the rock fabric. We believe that the entailed findings could influence our thinking on how best to produce these shales, wellbore stability, drilling fluid selection and other asset development actions.
Source-rock samples with varied amount of total organic content (TOC) were drilled perpendicular or parallel to the laminations. The samples were cut into twin plugs which were sequentially saturated by spontaneous imbibition of 5% KCl brine and diesel (oil). The NMR T2 measurements were used to determine the fluid imbibition rate and amount, as well as the porosity associated with organic and inorganic components of the source rocks. The fracture apertures were obtained via an application of characteristic T2 cutoff times to the NMR T2 distributions. The mineral elements, phases and TOC of the rocks were measured using X-ray Fluorescence (XRF), X-ray Diffraction (XRD) and HAWK pyrolysis, respectively.
The prevalence of surface relaxation on the NMR dynamics was prominent as the transverse relaxation took place at time scales (T2 ≤ 100 ms) much shorter than their bulk values. The overall wettability of the samples showed a mixed character as the brine and the oil had been intimately imbibed. Nevertheless, the details of the wetting behavior of the Eagle ford samples and the other samples were different. For instance, Eagle Ford samples imbibed larger volumes of brine and faster than oil, on the contrary the other samples imbibed larger volumes of oil and faster than brine.
The apparent preference of oil on the other samples is attributed to their high TOC compared to the Eagle Ford samples. Upon imbibition in these samples, brine is observed to flow along the clay rich bedding planes. In fact, the interaction between brine and clay is identified to be the potential driver of the rock stability problems especially near the wellbore; however it is constrained by the type of residing clays. The discrepancies in the wetting traits are magnified by the presence of fractures which enhanced the network connectivity of both hydrophobic and hydrophilic pores or even across them. Furthermore, the fractures allowed the fluids to surpass the vertical bedding planes and thus accelerating the fluid distribution processes inside the pore space. The fracture apertures were found to range from 1 μm to 15 μm which are typical values for source rocks (
Recovery mechanism due to brine injection (Dynamic Water, Low Salinity, etc.) in carbonate remains a point of discussion and widely open for research. As wettability alteration is heavily suggested as the main driver for recovery, this study focuses on the in-situ evaluation of wettability alteration due to multiple successive dynamic water flooding of carbonate cores plugs.
Five different core flooding with Nuclear Magnetic Resonance (NMR)
Initial results on two samples that are of similar
The results clearly indicate, for the first time, an in-situ wettability alteration due to Dynamic Water injection as demonstrated by NMR
The recent crash in the oil market has allowed the industry to reduce the pace of evaluation and completion decisions in unconventional reservoirs, and turn to a more science-based decision-making process for project execution. The traditional stimulation design based on the geometric spacing of induced fractures is now gradually changing to geological spacing (i.e., a design based on an understanding of the reservoir geology) to enhance hydraulic fracture stimulation effectiveness for drastically reduced cost. A methodical rock texture characterization of core samples and cuttings can provide powerful information that can be used reliably and cost-effectively to optimize fracture stimulation designs by placing frac stages based on rock characteristics. This paper presents a new method to quantify rock texture based on automated petrographic analysis that uses advanced microscopy image analysis from scanning electron microscopy (SEM) and optical microscopy. A procedure called "quantitative evaluation of minerals using a scanning electron microscope" (QEMSCAN) and optical microscopy analyses were used to image rock samples prepared from cores and cuttings. Rock texture parameters were extracted automatically using new digital data processing techniques. The information from automated petrographic analysis was used to determine the spatial distribution of all components including mineral composition, framework grains, matrix, cement, grain size and shape, pore size and shape, modes of contact between grains and the nature of porosity. The results showed that while mineral composition of rock is important, texture characterization is far more significant to understand rock behavior than has been reported in the industry. Our results demonstrate the importance of quantitative microscopy and how it can provide an understanding of the key relationship between rock texture and rock behavior.
A new method was produced to characterize rock texture quantitatively from advanced image analysis with the aid of an automated petrographic system.
Khalifeh, Mahmoud (University of Stavanger) | Saasen, Arild (Det Norske Oljeselskap and University of Stavanger) | Vrålstad, Torbjørn (SINTEF) | Larsen, Helge B. (University of Stavanger) | Hodne, Helge (University of Stavanger)
When a well reaches the end of its life-cycle, it is permanently plugged and abandoned. Since the first discovery in 1966 on the Norwegian Continental Shelf (NCS) till October 2014 nearly 5496 wells have been drilled. Of these wells, 3978 are development and 1518 are exploration wells. Of the development wells, 699 have permanently been abandoned and 279 are in temporary abandonment status. It is estimated that 3279 development wells need to be plugged and abandoned in the future. Besides, the number of wells which will be drilled in future should be added for plug and abandonment.
The costs of these P&A operations will be substantial. Hence, there is a need for technology development that will reduce the costs of all these operations. This development involves both techniques, tools and materials. The current work describes different plugging materials and important characteristics of permanent barriers with respect to long-term integrity. In addition, different roots of failure modes of permanent barriers have been discussed. Geopolymers are suggested as possible permanent plugging materials. Geopolymers are aluminosilicate materials, which solidify. A new geopolymeric material is introduced for the permanent zonal isolation and well plugging; an aplite-based geopolymer. Its placeability was studied by investigating the rheological behavior of the geopolymer slurries. The Bingham and Casson models selected to simulate the slurries' viscosities. Both models were fitted to the measured data. Strength development of the produced geopolymers showed sufficient compressive strength. X-ray powder diffraction was used to characterize the microstructure of the produced geopolymers. X-ray patterns showed formation of an amorphous phase. The measured permeability was in the range of nano Darcy. The initial result shows that the aplite-based geopolymer has the potential to be utilized as a permanent plugging material for well plugging and zonal isolation.
Trans-Tasman Resources Limited (TTR) was established in September 2007 in New Zealand to explore, assess and develop the off shore titano-magnetite iron sand deposits, located off the west coast of the North Island of New Zealand.
TTR holds exploration permit(s) and a prospecting license granting exclusive mineral rights over 9633 km2 of seabed, within New Zealand's territorial and Exclusive Economic Zone (EEZ) waters. Subsequent to a large airborne magnetic survey, TTR has undertaken a series of shallow and deep drilling campaigns which have defined an initial JORC1 mineral resource. This JORC compliant mineral resource was defined by Golders Associates on the basis of drilling campaigns that were performed using in house designed and operated drilling units, the first of its kind in the world.
TTR is developing innovative solutions for all aspects of its exploration and feasibility studies. In relation to exploration, TTR are competing in an environment which has offshore contractors and equipment focused on the petroleum industry, therefore it has been essential that TTR remain innovative to ensure cost effectiveness, fit for purpose and industry standards (JORC) are paramount. Exploration to date has enabled TTR to estimate an offshore titano-magnetite iron sand resource, using low cost marine reverse circulatory drilling units developed specifically for this purpose (patent pending) in conjunction with other exploration techniques.
The purpose of this paper will be to discuss some of the main challenges in the exploration and the subsequent engineering studies used in the feasibility studies for the development one of the world's first large off shore mineral resource of iron ore. The key strategic advantage of the envisaged off shore wet mining operation would be its much lower capital cost compared to land based operations, as no deep sea port or heavy gauge rail is required.
Sinha, Somnath (Exxon Mobil Upstream Research Company) | Braun, Edward M. (ExxonMobil Upstream Research Co.) | Passey, Quinn R. (ExxonMobil Upstream Research Co.) | Leonardi, Sergio Adrian (ExxonMobil Upstream Research Company) | Wood, Alexander C. (Exxon Mobil Corporation) | Zirkle, Timothy (Exxon Mobil Corporation) | Boros, Jeffrey Allan (ExxonMobil Upstream Research Co.) | Kudva, Ryan Ashok
Determination of permeability of unconventional reservoirs is critical for reservoir characterization, forecasting production, determination of well spacing, designing hydraulic fracture treatments, and a number of other applications. In many unconventional reservoirs, gas is produced from tight rocks such as shale. Currently the most commonly used industry method for measuring permeability is the Gas Research Institute (GRI) technique, or its variants, which involve the use of crushed samples. The accuracy of such techniques, however, is questionable because of a number of inadequacies such as the absence of reservoir overburden stress while conducting these measurements. In addition to questionable accuracy of crushed rock techniques, prior studies have indicated that there is significant variability in results reported by different laboratories that utilize crushed-rock technique to measure permeability on shale samples. Alternate methods are required to obtain accurate and consistent data for tight rocks such as shales. In this paper we discuss a robust steady-state technique for measuring permeability on intact tight rock samples under reservoir overburden stress. Permeability measurement standards for low permeability samples are critical for obtaining consistent results from different laboratories making such measurements, regardless of the method used for measuring permeability. In this paper we present permeability measurement standards developed based on first principles that serve as the "ground-truth?? for permeability in the 10 - 10,000 nanoDarcy range. These standards can be used to calibrate any permeability measurement apparatus used to measure permeability on intact tight rock samples such as shales, to enable delivery of consistent results across different laboratories conducting measurements on intact tight rock samples.
Unconventional reservoirs have burst with considerable force in oil and gas production worldwide. Shale Gas is one of them, with intense activity taking place in regions like North America. To achieve commercial production, these reservoirs should be stimulated through massive hydraulic fracturing and, frequently, through horizontal wells as a mean to enhance productivity.
In sedimentary terms, shales are fine-grained clastics rocks formed by consolidation of silts and clays. In log interpretation of conventional reservoirs, it is very common to observe that the clay parameters used to correct porosity and resistivity logs for clay effects are in fact read in shaly intervals rather than in pure clay. Although no considerable deviation have been observed in shaly sandstones, anyway these concepts and procedures must be reviewed to run log analysis in shale gas. Organic matter deposited with shales containing kerogen that matured as a result of overburden pressure and temperature, giving rise to source rocks that have yielded and expulsed hydrocarbons. Shale gas reservoir type is a source rock that has retained a portion of the hydrocarbon yielded during its geological history so that to evaluate the current hydrocarbon storage and production potential it is necessary to know the kerogen type and the level of TOC - total organic carbon - in the rock. Produced gas comes from both adsorbed gas in the organic matter and "free" gas trapped in the pores of the organic matter and in the inorganic portions of the matrix, i.e. quartz, calcite, dolomite.
In these unconventional reservoirs, gas volumes are estimated through a combination of geochemical analysis and log interpretation techniques. TOC, desorbed total gas content, adsorption isotherms, and kerogen maturity among other things can be measured in cores, sidewall samples and cuttings, in the laboratory. These data are used to estimate total desorbed gas content and adsorbed gas content which is part of the total gas. Also in laboratory, porosity, grain density, water saturation, permeability, mineral composition and elastic modules of the rock are measured. Laboratory measurement uncertainty is high and consistency between different providers appears to be low, with serious suspicions that procedures followed by different laboratories are the source of such differences. The permeability is one of the most important parameters, but at the same time, one of the most difficult to measure reliably in a shale gas. Core calibrated porosity, mineral composition, water saturation and elastic modules can be obtained through electric and radioactive logs. All these information is used to estimate log derived total gas volume which results are also subject to a high degree of uncertainty that must be overcome.
Once this key information is obtained, it is possible to estimate different gas in-situ volumes. Indeed, an estimate of porosity-resistivity based total gas in-situ and, on the other hand, geochemical based adsorbed gas in-situ can be performed. Log total gas in-situ can be, and it is advisable to do, compared with adsorbed gas estimations and also with another gas measurement called direct method - total gas desorption performed on formation samples. The difference between log total gas in-situ and adsorbed gas in situ should be the "free" gas in situ. Free gas occupies the pores of kerogen and matrix; also it can be stored in open natural fractures if such fractures are present.
A multidisciplinary approach to shale characterization in a variety of North American gas- and liquids-rich shale plays has lead to improved understanding of the bulk physical, chemical and mechanical properties of these deposits and their geologic history. This effort is leading to successful exploitation of these enigmatic resources. Microfacies analysis of mudrocks provides a platform for upscaling from the "nano?? to the regional scale, and results in comprehensive mudrock characterizations.
Microfacies analysis of mudrock types within a select stratigraphic interval in a basin leads to the recognition of mudrock lithofacies. Lithofacies identification allows for calibration of petrophysical models, documentation of basinspecific variations in mudrock composition and microfabrics, the distribution of organic-rich members of these intervals, definition of the mechanical stratigraphy for completion design, and provides the litho-stratigraphic building blocks for predictive sequence stratigraphic models.
Successful exploration and exploitation of mudrocks as resources can be advanced when the recognition of mudrock lithofacies provides a methodical means to tie together the geologic, chronostratigraphic, geochemical and petrophysical data from a diverse spectrum of physical scales and technical disciplines.
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.