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 (
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.
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
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.
Production of water is inevitable from reservoirs particularly in aged fields. Water is very useful for efficient reservoir management but could be a nuisance when it does not contribute to hydrocarbon production and cause diverse problems such as corrosion, sand production, etc, in a well. High water cut increases the potential of sand production risks. Several mechanisms of sanding, sand control models and measures exist in the industry to ensure safe operation of facilities. In this work, series of laboratory tri-axial compressible strength tests on different core samples was performed to investigate and quantify the effect of water-cut on sandstone strength and sand production. The tri-axial compressive strength tests were performed under in-situ confining pressures. The samples were initially 100% saturated with brine at some time and other times the water-oil saturations were varied. The results showed that the effect of water-cut on sandstone strength and sand production is very significant for all sandstones tested. Also, strength reduction is more significant for 100% water saturated samples than samples with less water saturation for all samples. Hence, water saturation-induced rock strength reduction is the most significant factor governing sand production. Although, failure of rock is pre-requisite for sand production, the failure does not always lead to sand production.
Recently, a set of six pseudocomponent (PC) schemes was proposed for general characterisation of the Nigerian heavy oil and bitumen 1. However, the performance of the schemes is yet to be assessed. Given the laboratory-measured viscosity versus temperature relationship of a sample of the Nigerian bitumen, this paper employs the PC schemes to construct and tune fluid models to the viscosity dataset. Although all the cases show reasonable agreements (average absolute deviation below 25%) between measured and fitted data, the best and worst performances are obtained with the 4-PC and 1-PC schemes, respectively.
The tuned fluid models are then applied in thermal reservoir simulation studies. With a generic but representative reservoir-sector model, the dynamic response of the Nigerian bituminous deposit to the recovery method of steam-assisted gravity drainage (SAGD) is investigated. Simulation results indicate excellent consistency among the 3, 4, and 5-PC schemes but the 1- and 2-PC schemes deviate markedly from the higher-component approximations. As might be expected, the 1-PC model can not explain the solution gas reported in the Nigerian bituminous belt.
From the specific case studied, at least three PC's may be required to enable satisfactory characterisation of the Nigerian heavy crude for general applications. This initial conclusion follows from the comparative accuracy and computational efficiency of the ternary (3-PC) model. Future efforts should focus on generating additional experimental datasets, including but not limited to viscosity, on the Nigerian bitumen and evaluating the robustness of our preliminary conclusion.
While the popularity of the numerical simulation approach (such as the Monte Carlo) for probabilistic reserves estimation has never been higher among geoscientists and reservoir engineers, comparatively little attention has been paid to the techniques needed to correctly model the required petrophysical input parameters.
Petrophysical well analyses typically end in the presentation of average reservoir property values for porosity, water saturation and net-to-gross but these lone averages, while adequate for deterministic reserves estimates, obviously fail to account for the inherent reservoir petrophysical properties uncertainty within a probabilistic reserves estimate. Of more importance for probabilistic reserves estimation is a statistical model comprising Probability Distribution Functions (or PDFs) of the aerial uncertainty in reservoir properties resulting from a larger reservoir being sampled by a relatively small discrete well population.
Monte Carlo simulations are typically used to estimate probabilistic reserves but the accuracy of these are strongly correlated to the quality of the input probability distributions. Many errors in the outputs of reserves models could be traced back to assigning incorrect values to the descriptive parameters of a distribution, and indeed the selection of an appropriate distribution. Therefore, if probability distributions are to be used to represent statistical assumptions of petrophysical properties in reserves estimates, then the way petrophysical averages data is analysed and transformed into PDFs becomes of crucial importance. Hence, the purpose of this paper is to present practical ideas for achieving the definition of probability distributions that best represent the petrophysical property input into probabilistic reserves estimates.
The focus on petrophysical properties in this paper is not arbitrary or accidental but, instead, reflects the centrality of petrophysical input as a driver of accuracy in reserves estimates.
Jiecheng, Cheng (Daqing Oilfield Co. Ltd.) | Wanfu, Zhou (Daqing Oilfield Co. Ltd.) | Yusheng, Zhang (Daqing Oilfield Co. Ltd.) | Xu, Guangtian (Daqing Oilfield Co. Ltd.) | Ren, Chengfeng (Daqing Oilfield Co. Ltd.) | Zhangang, Peng (Daqing Oilfield Co. Ltd.) | Bai, Wenguang (Daqing Oilfield Co. Ltd.) | Zongyu, Zhang (Daqing Oilfield Co. Ltd.) | Xin, Wang (Daqing Oilfield Co. Ltd.) | Fu, Hairong (Daqing Oilfield Co. Ltd.) | Qingguo, Wang (Daqing Oilfield Co. Ltd.) | Xianxiao, Kong (Daqing Oilfield Co. Ltd.) | Lei, Shi
ASP flooding in Daqing oilfield commenced from 1980s. To date, industrial pilot tests have been carried out in three blocks. The averaged recovery was increased by 20%. On the other hand, scaling issue caused high frequent pump failures. Large amount of scale building up in the producers wellbore and downhole equipments with high speed, which resulted in the averaged running life of lifting system decreased from 599 days of water flooding period to 60 days. Further more, some producers' running lives were only around 30 days, leading to higher production cost and lower production rate as well.
Study indicated that, the scaling principle and scale composition in producing wells differed from each other and was difficult to be predicted accurately. In this study, after tracking and measuring the ion in produced fluid for the whole process from water flooding, polymer flooding to ASP flooding and analyzing composition of the scale on different parts of scaling well, the criterion and distinguishing chart of scaling tendency had been set up initially. The criteria were applied in 102 wells in ASP flooding area, the accordance rate was more than 90 percent. Based on that, scaling inhibition technology was timely performed for predicted scaling wells, and the running lives were increased from 40 days to above 200 days. This paper presented the process of the study and is greatly helpful for APS flooding in commercial scale.
Roshanaei Zadeh, Gholam Abbas (National Iranian South Oil Co) | Moradi, Siyamak (Islamic Azad University-Mahshahr Branch) | Dabir, Bahram (Amirkabir University of Technology) | Ali Emadi, Mohammad (NIOCRTD) | Rashtchian, Davood (Sharif University of Technology)
Asphaltene precipitation during natural depletion and miscible gas injection is a common problem in oilfields throughout the world. In this work, static precipitation tests are conducted to investigate effect of pressure, temperature and gas type and concentration on asphaltene instability. Three different oil samples are studied under reservoir conditions with/without nitrogen and methane injection. Besides applying common thermodynamic models, a new scaling equation is presented to
predict asphaltene precipitation under HPHT gas injection. Published data from literature are also used in model development. The scaling approach is attractive because it is simple and complex asphaltene properties are not involved in the calculations. Moreover, the proposed model provides universal parameters for different fluid samples in a wide range of pressure and temperature that makes it novel for evaluation of future gas injection projects when simple PVT data are available.
Keywords: Nitrogen injection/Asphaltene precipitation/Pure solid modeling/Scaling equation.
Miscible/partial miscible gas injection is a promising enhanced oil recovery technique for many reservoirs (Huang et al, 1993). It is well known that the injection of CO2, N2 and hydrocarbon gases change the solubility of heavy components in the reservoir oil and causes asphaltene instability (Yang et al., 1999; Srivastava et al., 1999; Jamaluddin et al., 2002; Takahashi et al., 2003; Hu et al., 2004; Negahban et al., 2005; Verdier, 2006; Dehghani et al., 2008).
Hirschberg et al. (1988) applied polymer solution theory to present a solubility model for asphaltene precipitation. In this approach, asphaltene was expected as a heavy liquid and phase behavior calculations were performed for gas-oil and oilasphaltene systems. The model was later modified to account for asphaltene polydispersity (Monteagudo et al., 2001). Yang et al. (1999) proposed a modified Hirschberg model and defined asphaltene solubility parameter as a function of specific gravity, molecular weight and boiling point. Pazuki et al. (2006) defined an interaction parameter between polymer and solvent and correlated it to molecular weight of solution and asphaltene. Later, they applied the perturbation theory and proposed a new equation of state to study phase behavior of crude oil and asphaltene (2007). Vafaie-Sefti et al. (2003, 2006) incorporated association term in Peng-Robinson equation of state. Simple association factors were obtained from molecular weight distribution (fractional molecular weight) and average asphaltene molecular weight. However, this model includes more uncertain matching parameters compared to previous attempts.
Leontaritis and Mansoori (1987) presented a colloidal model by applying statistical thermodynamics. They defined a critical resin concentration (CRC) to estimate critical chemical potential of resins. According to this approach, asphaltene precipitation will occur if chemical potential of resins in the mixture is less than the critical value. Escobedo and Mansoori (1994) concluded that this model is accurate for determination of onset of asphaltene precipitation and does not quantify the precipitates. Later, Wang et al. (2001) mentioned that some experimental evidences were against this model.
Pan and Firoozabadi (1998, 2000) proposed thermodynamic micellization model that describes asphaltene precipitation by minimizing total free Gibbs energy of system (including asphaltene monomers and micelles). Although their model considers colloidal nature of oil, it must be optimized to comprise effect of resins and precipitants successfully.