This paper shows how greater scientific rigor in discussions of modelling 3D saturations in the Middle East can lead to better understanding of the reservoirs. It demonstrates with examples how vocabulary limits ability to solve problems related to saturations, compartmentalization, and permeability. It raises the bar on technical discussions of saturation.
"Saturation-height modelling", "transition zones", and "Thomeer hyperbolas" are examples of terms that repeatedly confuse discussions of modelling 3D saturations in the Middle East. Vocabulary exposes a lack of scientific rigor, impedes progress, and leads to notable failures. Saturation is not merely a function of height. At the very least, it also depends on porosity, permeability, fluid densities, interfacial tension, and contact angle. Limiting it to height requires adding in all of these other functionalities as afterthoughts rather than incorporating them naturally through dimensional analysis. Most glaringly, it obscures the very useful role that saturations have in constraining permeability modelling and identifying reservoir compartments.
"Transition zones" focus on saturation and take emphasis away from relative permeability and fractional flow. Bimodal pore systems (abundant in the Middle East) can have such low relative permeability to water at high saturations that even 70% water saturation can produce dry oil. In such cases, talk of a transition zone is counterproductive as it implies high water production.
"Thomeer hyperbolas" reveal biases in how to fit capillary pressure curves. Force-fitting all data with a single model is inadequate. It takes emphasis away from understanding pore systems of rocks in favor of promoting a single-minded view. These examples and their implications are discussed in detail.
The existing literature is replete with incomplete explanations and misunderstandings that lead to notable failures in modelling Middle Eastern fields. Understandings predicated on simplified descriptions of homogeneous reservoirs are no longer sustainable. A more scientifically rigorous methodology is presented.
Hassan, Amjed (King Fahd University of Petroleum & Minerals) | Mahmoud, Mohamed (King Fahd University of Petroleum & Minerals) | Al-Majed, Abdulaziz (King Fahd University of Petroleum & Minerals) | Al-Nakhli, Ayman (Saudi Aramco) | BaTaweel, Mohammed (Saudi Aramco) | Elktatany, Salaheldin (King Fahd University of Petroleum & Minerals)
Condensate banking is a common problem in tight gas reservoirs because it diminishes the gas relative permeability and reduces the gas production rate significantly. CO2 injection is a common and very effective solution for condensate removal in tight gas reservoirs. The problem with CO2 injection is that it is a temporary solution and has to be repeated frequently in the field in addition to the supply limitations of CO2 in some areas. Also, the infrastructure required at the surface to handle CO2 injection makes it expensive to apply CO2 injection for condensate removal.
In this paper, a new permanent technique is introduced to remove the condensate by using a thermochemical technique. Two chemicals will be used to generate in-situ CO2, nitrogen, steam, heat, and pressure. The reaction of the two chemicals downhole can be triggered either by the reservoir temperature, or a chemical activator. Two chemicals will start reacting and produce all the mentioned reaction products after 24 hrs. of mixing and injection. Also, the reaction can be triggered by a chemical activator and this will shorten the time of reaction. Coreflooding experiments were carried out using actual condensate samples from one of the gas fields. Tight sandstone cores of 0.9 mD permeability were used.
The results of this study showed that, the thermochemical reaction products removed the condensate and reduced its viscosity due to the high temperature and the generated gases. The novelty in this paper is the creation of micro-fractures in the tight rock sample due to the in-situ generation of heat and pressure from the thermochemical reaction. These micro-fractures reduced the capillary forces that hold the condensate and enhanced its relative permeability. The creation of micro-fractures and in turn the reduction of the capillary forces can be considered as permanent condensate removal.
The task of reliable characterization of complex reservoirs is tightly coupled to studying their microstructure at a variety of scales, which requires a departure from traditional petrophysical approaches and delving into the world of nanoscale. A promising method of representatively retaining a large volume of a rock sample while achieving nanoscale resolution is based on multiscale digital rock technology. The smallest scale of this approach is often realized in the form of working with several 3D focused-ion-beam–scanning-electron-microscopy (FIB-SEM) models, registration of these models to a greater volume of rock sample, and estimation and scaling up of model local properties to the volume of the entire sample. However, a justified and automated selection of representative regions for building FIB-SEM models poses a big challenge to a researcher. In this work, our objective was to integrate modern SEM and mineral-mapping technologies to drive a justified decision on location of representative zones for FIB-SEM analysis of a rock sample. The procedure is based on two experimental methods. The first method is automated mapping of sample surface area with the use of backscattered electrons (BSEs) and secondary electrons (SEs); this method has resolution down to nanometers and spatial coverage up to centimeters, also referred to as large-area high-resolution SEM imaging. The second method is automated quantitative mineralogy and petrography scanning that allows covering sample’s cross section with a mineral map, with resolution down to 1 µm/pixel. Data gathered with both methods on millimeter-sized cross sections of rock samples were registered and integrated in the paradigm of joint-data interpretation, augmented with computer-based image-processing techniques, to provide a reliable classification of nanoscale and microscale features on sample cross sections. The superimposed SEM and mineral-map images were combined with physics-based selection criteria for reasonable selection of FIB-SEM candidates out of a great number of potential sites. In the result, a semiautomated work flow was developed and tested. Demonstration of the work flow is made on one of Russia’s most promising tight gas formations, where the characteristic dimension of void-space objects spans from a single nanometer to millimeters. An example of an optimized site selection for FIB-SEM operations is discussed.
Muqtadir, Arqam (King Fahd University of Petroleum & Minerals) | Elkatatny, S. M. (King Fahd University of Petroleum & Minerals) | Mahmoud, M. A. (King Fahd University of Petroleum & Minerals) | Abdulraheem, A. (King Fahd University of Petroleum & Minerals) | Gomaa, A. (BP America)
ABSTRACT: The presence of pore fluid tends to affect the rock's physical and mechanical properties. It potentially causes drilling problems, casing failures and improper fracture propagation. It is vital to understand how much the strength of the rock is affected when saturated with fluids. Low porosity, permeability and complexities in pore structures can further thwart the effect. The effect of saturating fluid on the dynamic and static properties of low permeability Scioto sandstone outcrop samples was studied in this paper. It was seen that the Unconfined Compressive Strength (UCS) was decreased by 9% for oil saturated rocks and 25% for brine saturated rocks whereas the reduction in the tensile strength was 20% and 42% respectively. The UCS samples were monitored with acoustic emission (AE) and exhibited a series of events.
Geomechanical parameters of rocks are influenced when exposed to fluids. As the water saturation increases, a reduction in the Unconfined Compressive Strength (UCS) (Y agiz and Rostami, 2012) and Young's modulus is seen, while Poisson's ratios tends to increase (Widarsono et al., 2001). Usually sedimentary rocks are more affected by the water saturation than the igneous and metamorphic rock (Wong et al., 2016).
For carbonates, DeVilbiss (1984) partially saturated limestone rock with water and saw an attenuation in the acoustic velocities. Brignoli et al., (1995) performed UCS on fully saturated limestones and saw a 15 to 20% reduction in the Young's modulus. Fabricius & Eberli (2009) also saw a similar decrease.
Zhang et al., (2017) studied the effect of different water saturations on the geomechanical properties of siltstones. The highest reduction in strength was observed at 10% saturation. It was seen that as the water saturation decreased, the volumetric strain of the cracks and the sample decreased as a result from water easing crack initiation and propagation.
Mc Carter (2010) and Perera et al., (2011) performed UCS on coal and sandstones and saw a decrease in UCS and Young's modulus as water saturation increased. Labuz & Berger (1991) saw a decrease of 15 % in the Young's modulus as water saturation increased in granite while Vasarhelyi (2003) saw the same effect in Hungarian volcanic rocks. Henao et al., (2017) reported a significant decrease in strength in sandstone rocks when saturated with brine while a moderate decrease when saturated with dodecane.
Proximity Sensing was recently proposed as way to simultaneously increase both range and resolution in cross-well EM tomography. The approach is applicable to reservoirs with resistive seals. Earlier reports were based on Finite Element Models (FEM) of layered structures, with dielectric and conductivity contrasts matching those of known reservoirs.
Experimental work, now reported, is consistent with expectations based on FEM simulations. Synthetic layered structures have been investigated using a 1.3 GHz Ground Penetrating Radar (GPR) system. Scaled reservoir model was constructed in a one-meter tank comprising sand with filled with fluids of variable dielectric constant and conductivity. In this system, dry sand, brine-saturated sand and a polymer foam provide a useful mimic for the electrical properties expected for a carbonate reservoir sealed by anhydrite. Water saturated porous media served as model bounding layers in analogy to known geologic structures. Data were recorded in the time domain using EM transients. Observed trends in velocities and amplitude shifts were consistent with FEM models. Interestingly, polarization dependent signal transport first indicated by FEM modeling was supported by these experimental results.
Results to date indicate that greatly increased EM propagation can be achieved through resistive geologic layers than directly through relatively conductive reservoir media. We confirm that these layers act as planar transmission lines and not as waveguides – meaning that there is no hard lower cutoff frequency and longer wavelengths can be used to sense and characterize reservoir fluids proximal to the dielectric channel. The results also confirm that variations in bounding layers modulate the amplitude and velocity of the signal in the dielectric channel and thereby demonstrate concept of Proximity Sensing.
These results support a new technical direction for EM characterization of reservoirs, especially in conjunction with magnetic contrast agents, enabling efficient localization of by-passed oil and mapping remaining oil columns in mature reservoirs.
Long-term petroleum reservoir management ideally optimizes production of oil while avoiding brine production and minimizing well count and complexity. Given imperfect knowledge of reservoir structure, significant inhomogeneity and dynamic multi-phase fluid saturation, this is a difficult and long-standing problem that would greatly reward improved methods for observing the state and structure of the reservoir in near real-time. This is particularly true in the case of mature fields in secondary production on waterflood. Modern reservoir models derived from 3D seismic, well logs and history matching are certainly a vital tool for reservoir management. However, our lack of knowledge about large-scale inhomogeneity, including facture corridors, prevent anticipation of early water breakthrough and bypass of significant volumes of oil. As such, there is a great need for imaging tools that can locate flood fronts, detect bodies of bypassed oil and map the remaining oil column thickness across the entire reservoir with sufficient resolution to guide key management decisions. Naturally, reservoir management would be easy if we had imaging modalities with petrophysical scale resolution (e.g. well logs ∼ 0.1 meter) over geophysical survey scales (e.g. seismic ∼ kilometers). However, imaging resolution requirements that can yield valuable and actionable information is probably much less challenging than that, and depends on direction and scale of the particular field under consideration. For the purposes of this paper, we will assert that for giant and super-giant fields (>> 1 B bbl), imaging modalities with resolution on the order of one meter vertically and up to several hundred meters laterally could respectively determine remaining oil column and flooded/bypassed volumes with sufficient accuracy to greatly improve reservoir management practice and development planning. Historic approaches for generating this kind of actionable information include direct full volume imaging using acoustic and low frequency electromagnetic (EM) probes. A new approach based on indirect EM imaging via Proximity Sensing will be described experimentally here.
Hydraulic fracturing has been widely used for unconventional reservoirs including organic-rich carbonate formations for oil and gas production. During hydraulic fracturing, massive amount of fracturing fluids are pumped to crack-open the formation and only a small percentage of the fluid is recovered during the flowback process. The negative effects of the remaining fluid on the formation such as clays swelling and reduction of rock mechanical properties have been reported in literatures. However, effects of fluids on source rock properties, especially the microstructures, porosity and permeability, are scarcely documented. In this study, microstructure and mineralogy changes induced in tight carbonate rocks by imbibed fluids and corresponding changes in permeability and porosity are reported.
Two sets of tight organic-rich carbonate source rock samples were examined. One sample set was sourced from the Middle East field and the other was an outcrop from Eagle Ford Shale that is considered to be analogous to the one from the Middle East field. Three fracturing fluids, namely 2% KCl, 0.5 gpt slickwater and synthetic seawater, were used to treat the thin-section of the source rock and core samples. Modern analytical techniques such as SEM and EDS were used to investigate the source-rock morphology and mineralogy changes prior and after the fluid treatment at micron-scale level. Porosity and permeability as a function of confining pressures were quantified on core samples to investigate changes in flow properties due to the fracturing fluids treatments.
The SEM and EDS results prior to and after fracturing fluid treatments on the source rock samples showed the microstructural changes in all three fluids. In 2% KCl and slickwater fluid, reopening of some mineral-filled natural fractures was observed. The enlargement of micro-fractures was slightly more noticeable for samples treated with 2% KCl in comparison to slickwater at the micron-scale level. In one sample, dissolution of organic matters was captured in slickwater fluid treated rock sample. Some mineral precipitation and new micro-fractures generation were observed for samples treated with seawater. The new micro-fractures generation and mineral dissolution through the fluid treatment would result in the increases in both porosity and permeability, while the mineral deposition would result in permeability decrease. The overall increase in absolute gas permeability was quantified by the experimental measurements under different effective stresses for the core plug samples. This effect on absolute gas permeability increase has an important implication for hydrocarbon recovery from unconventional reservoirs.
This study provides experimental evidences at different scales that aqueous-based fracturing fluid may potentially have positive effect on gas production from organic-rich carbonate source rock by increasing absolute gas permeability through mineral dissolution and generation of new or re-opening of old microfractures. This observation will be beneficial to the future usage of fresh and seawater based fluids in stimulating gas production for organic-rich carbonate formations.
Alfarge, Dheiaa (Missouri University of Science and Technology) | Wei, Mingzhen (Missouri University of Science and Technology) | Bai, Baojun (Missouri University of Science and Technology) | Almansour, Abdullah (King Abdulaziz City for Science and Technology)
Disproportionate Permeability Reduction (DPR) is often used as a water-shutoff treatment in production wells when conventional solutions such as mechanical isolations are difficult to perform. Although this property has been well documented by different investigators, the performance of DPR treatments in field applications has varied between success and failure without understandable reasons. This work investigated DPR performance in different scenarios to see when, where and at which conditions DPR treatments can give better results. Numerical simulation methods were used to simulate different scenarios happening in oil and gas fields such as five-spot pattern system and linear-system, with different number of layers, with and without crossflow. The possibility of using DPR treatment in hydraulically-fractured reservoirs was also investigated since many reports indicated that there is an increase in water production after some oil and gas reservoirs being hydraulically-fractured. Moreover, the physical reasoning behind the variations in DPR performance for different scenarios has been extensively discussed.
The results explored that DPR performance was excellent in both of water-cut reduction and oil-recovery improvement when the flow regime was viscous dominated (viscous-gravity number<0.1). On the other hand, when the flow regime was gravity dominated (viscous-gravity number >10), the effective period of DPR treatment was short-term remedy. Secondly, when the high-K layer is existed at the lower-zone of oil or gas reservoir is a good candidate for DPR treatment as compared when the high-K layer located at the upper zone. Furthermore, selecting the correct time to perform DPR treatments generally has a significant role to mitigate water production. Finally, the dimensions of treated fracture are the key components to get a successful DPR-treatment in fractured reservoirs.
Water production is considered one of the most dominant problems in matured oil and gas wells. Difficulty of this problem comes from the significant cost associated with the water production. This cost is resulted from separating, treating, and disposing of produced water which is approximately estimated as $50 billion annually (Hill et al., 2012). Different solutions were suggested to control the excessive water production according to the sources and reasons of the produced water in hydrocarbon reservoirs. In some situations, all the suggested methods to control water production would not be effective except DPR (Mennella et al., 2001). Therefore, DPR treatment is one of the attractive methods to mitigate water production through production wells, not only by its low cost, but also by its easiness to be performed. The DPR property is considered very important in production wells when the mechanical isolation is very difficult to perform (Liang et al., 1993). And, there are some situations which need DPR treatments to be performed; otherwise the well would be abandoned (Mennella et al., 2001).
Ross, T. S. (New Mexico Institute of Mining & Technology) | Rahnema, H. (New Mexico Institute of Mining & Technology) | Nwachukwu, C. (New Mexico Institute of Mining & Technology) | Alebiosu, O. (ConocoPhillips Co) | Shabani, B. (Oklahoma State University)
Steam injection—a thermal-based enhanced oil recovery (EOR) process—is used to improve fluid mobility within a reservoir, and it is well known that it yields positive results in heavy-oil reservoirs. In theory, steam injection has the potential of being applied in light-oil reservoirs to enable vaporization of in-situ reservoir fluids, but field developments and scientific studies of this application are sparse. Conventional displacement methods like water-flooding and gas-flooding have been applied to some extent, however, oil extraction in such reservoirs relies on recovery mechanisms like capillary imbibition or gravity drainage to recover oil from the reservoir matrix. Furthermore, low-permeability reservoir rocks are associated with low gravity drainage and high residual oil saturation.
The objective of this study is to evaluate the potential of steam injection for light (47°API) oil extraction in naturally-fractured reservoirs. It is theorized that this method will serve as an effective tool for recovery of light hydrocarbons through naturally-fractured networks with the benefit of heat conduction through the rock matrix. This research investigates the application of light-oil steamflood (LOSF) in naturally- fractured reservoirs (NFR).
A simulation model comprised of a matrix block surrounded by fracture network was used to study oil recovery potential under steam injection. To simulate gravity drainage, steam was injected through a horizontal well completed in the upper section of the fracture network, while the production well was completed at the bottom of the fracture network. The simulation included two different porous media: (1) natural fractures and (2) matrix blocks. Each of these porous media was assumed to be homogeneous and characterized based on typical reservoir properties for carbonate formations. This study also analyzed the impact of different recovery mechanisms during steam injection for a light-oil sample in NFR, with reservoir sensitivity examined, based on varying amounts of vaporization, injection rate, permeability, matrix height and capillary pressure. Of these, vaporization was found to be the dominant factor in the application of LOSF in NFR, as described in detail within the results.
Giant reservoirs such as Lula (Santos Oil Basin, Brazil) and Ghawar (Saudi Arabia) have high-permeability intervals, known as super-k zones, associated with thin layers. Modeling these small-scale flow features in large-scale simulation models is difficult. Current methods are limited by high computational costs or simplifications that mismatch the representation of these features in simulation gridblocks. This work has two purposes: present an upscaling work flow to integrate highly laminated or interbedded reservoirs with thin, highly permeable layers in reservoir simulations through a combination of an explicit modeling of super-k layers using the Parsons (1966) formula and dual-medium flow models, and compare this method with two conventional upscaling approaches that are available in commercial software.
We use the benchmark model UNISIM-II-R (Correia et al. 2015a), a fine single-porosity grid dependent on field information from the Brazilian presalt and Ghawar oil fields, as the reference solution to compare the upscaling matching between the three methods. We compare oil recovery factor (ORF), water cut (WC), average reservoir pressure (RP), water front, and the time consumption for simulation. Our proposed Parson’s dual-medium (PDP) methodology achieved better upscaling matches with the reference model and had minimal time consumption compared with the representation of super-k layers through an implicit matrix modeling by single-porosity flow models (IMP) and through the explicit representation of super-k zones in the fracture system of dual-medium flow models (DFNDP).
Miah, Mohammad Islam (Department of Process Engineering Oil and Gas Program, Memorial University of Newfoundland, St. John's) | Deb, Pulok Kanti (Department of Process Engineering Oil and Gas Program, Memorial University of Newfoundland, St. John's) | Rahman, Md. Shad (Department of Process Engineering Oil and Gas Program, Memorial University of Newfoundland, St. John's) | Hossain, M. Enamul (Department of Process Engineering Oil and Gas Program, Memorial University of Newfoundland, St. John's)
Petroleum reservoir rock and fluid properties vary during any pressure disturbances or thermal actions in the reservoir formation. It is important to consider the rock properties such as permeability, porosity, etc. and fluid properties such as viscosity, PVT properties etc. as a function of time for applications including geothermal actions, chemical reactions, and other geological activities in the sub-surface of the reservoir complex structure. Memory is the effect of past events on the present and future course of developments. The continuous alteration of rock/fluid properties can be characterized using memory concept. It is also significant to consider the rock, and fluid properties as a function of time, and the inclusion of recently introduced memory concept in petroleum engineering study. In this paper, a detailed review of the existing techniques and models of reservoir characterization is presented. This study will provide an inclusive information on the present status of memory-based fluid flow modeling, rock and fluid properties models development under spurious assumptions during reservoir characterization. The variations of porosity and permeability over the distance are presented which are from the wellbore towards the outer boundary of the reservoir with time in actual reservoir conditions. Reservoir porosity and permeability are directly related to the reservoir formation depth and pressure. Reservoir porosity and pressure are decreasing over time. Permeability is changed over distance because it is directly related to the pressure of the complex reservoir system. In addition, the viscosity is a function of temperature of crude oil. Since memory-based diffusivity equation through porous media is more rigorous, as it incorporates continuous alteration of rock and fluid, and viscosity of oil predicts results from memory models should be preferred and reliable during the convergence process in reservoir simulators. This paper also aids as an insight of the future research opportunity toward developing models for reservoir properties, and models for fluid flow through porous media in the complex reservoir by the application of memory concept.