Aljawad, Murtada Saleh (King Fahd University of Petroleum and Minerals)
Acid fracture operations in carbonate formations are used to create highly conductive channels from the reservoir to the wellbore. Conductivity in calcite formations is expected to be highest near the wellbore, where most of the etching occurs. The near wellbore fracture etched-width profile can be estimated from the measured temperature distribution. Temperature data can be obtained from fiber optic distributed temperature sensing (DTS) installed behind casings to monitor fracturing operations.
Heat transfer is commonly coupled in acid fracture models to account for temperature's effects on acid reactivity with carbonate minerals. Temperature profiles are usually evaluated during simulations of fracture fluid injection, but seldom during fracture closure. Since most of the acid is spent during injection, many models have assumed that the remaining acid reacts proportionally along the fracture length. Because of this assumption, neither acid spending nor temperature is usually simulated during fracture closure.
In this study, a fully integrated temperature model was developed wherein both the acid reaction and heat transfer were simulated while the fracture was closing. At each time step, transient heat convection, conduction, and generation were calculated along the wellbore, reservoir, and fracture dimensions. Modeling temperature during this transient period provides a significant understanding of the fracture etched-width distribution. During shut-in, cold fracture fluids are heated, mainly because of heat flow from the formation to the fracture. The amount of fluid stored in the fracture determines how fast the fluid is heated. Wider fracture segments contain larger amounts of cold fracture fluids, resulting in it taking longer to reach the reservoir temperature. Because of this phenomenon, near a wellbore, the vertical fracture etched-width profile can be determined from the temperature distribution. Also, minerals' spatial distributions along the wellbore's lateral can be estimated in multistage acid fracturing. This is done by minimizing the difference between the observed and modeled temperatures.
This evaluation of etched width profiles at the fracture entrance provides an estimation of fracture-conductive channel locations. Moreover, it has significantly improved the understanding of mineralogy distribution in multi-layer formations. This information will be particularly useful when designing acid fracturing jobs in nearby wells or revisiting the same wellbore for further stimulation.
Weirong, Li (Xi'an Shiyou University) | Zhenzhen, Dong (Xi'an Shiyou University) | Gang, Lei (King Fahd University of Petroleum and Minerals) | Cai, Wang (Research Institute of Petroleum Exploration & Development, Petrochina) | Huijie, Wang (Peking University)
A local refined model, using micro-seismic data to model fracture geometry, is presented to study huff-npuff surfactant injection in a tight oil reservoir. The goal of this study is to understand the key parameters that control the surfactant huff-n-puff performance in tight oil reservoirs. In this new approach, natural fractures in tight oil reservoir is described by dual permeability model, and stimulated reservoir volume (SRV) based on micro-seismic datais is modeled by local refined grid. In the study, sensitivity analysis is carried out to optimize oil recovery, such as wettability change, interfacial tension, surfactant adsorption, huff-n-puff cycle, etc. The results indicate that surfactant injection is a favorable method to mobilize oil in tight oil reservoirs; wettability alteration and interfacial tension of surfactant are the dominant mechanisms for the oil recovery through surfactant injection; surfactant adsorption is a key element to the success of the wettability alteration process; and soaking time does not have obvious impact on recovery. The incremental oil recovery factor over primary production for 15 years of total production is up to 3.5% of OOIP that doubles the recovery from the primary production. The study gives new method to study surfactant injection in the tight oil reservoirs when micro-seismic data available. It can be helpful for modeling other EOR process in tight oil reservoirs.
Mustafa, Ayyaz (King Fahd University of Petroleum and Minerals) | Abdulraheem, Abdulazeez (King Fahd University of Petroleum and Minerals) | Abouelresh, Mohamed Ibrahim (King Fahd University of Petroleum and Minerals) | Sahin, Ali (King Fahd University of Petroleum and Minerals)
The lower Silurian Qusaiba Shale is one of the major source rocks for Paleozoic petroleum reservoirs in Saudi Arabia and is considered a potential shale gas resource. The study aims to evaluate the prospectivity and improve the production potential of Qusaiba shale by defining the lithofacies and mineralogy as controlling factors for brittleness and other mechanical parameters.
The continuous 30 feet subsurface cores and log data of Qusaiba Shale from Rub’ Al-Khali Basin were utilized for the study. Geological characteristics on the core were fully demonstrated in terms of size, mineralogy, color, primary structures and diagenetic features to identify lithofacies. In addition, 30 thin sections were used to study micro scale geological characteristics. The powder X-ray diffraction (XRD) was used to determined the mineralogical compositions. Surface morphology visualization and elemental analysis were performed using the scanning electron microscope supplemented with energy dispersive spectroscopy (SEM-EDS). Acoustic velocity measurements and compressive strength tests were performed on 15 core plugs (5 from each lithofacies).
Based on the above-mentioned analyses, three lithofacies were identified: (1) Micaceous laminated organic-rich mudstone facies (Lithofacies-I), (2) Laminated clay-rich mudstone facies (Lithofacies-II), and (3) Massive siliceous mudstone facies (Lithofacies-III). Mineralogical composition resulted in variable amounts of quartz ranging from 39 to 40, 45-55 and 60 to 78% for Lithofacies-I, II and III, respectively. Lithofacies-I having relatively lower quartz and higher clay percentage and total organic content (12% by volume) exhibited low stiffness. Mineralogy- and elastic parameters-based brittleness indices exhibited ductile behavior of this lithofacies. Lithofacies-II with relatively higher quartz (45 to 55%) and lower clay contents and TOC (3-5%) than Lithofacies-I resulted in relatively higher stiffness and brittleness. The brittleness index exhibited brittle behavior for silica rich Lithofacies-III (low TOC< 3%) as reflected by Young's modulus (average 32 GPa) and low Poisson's ratio (average 0.25). Hence, it is concluded that mineralogy and geological characteristics are the main controlling factors on mechanical properties and brittleness. The integration of three essential disciplines i.e. geology, mineralogy and geomechanics, plays the key role to better evaluate the production potential by highlighting the sweet spots within the heterogeneous shale gas reservoirs.
Up to 2010, 44.55% of 312 EOR's project for light oil implemented around the world in sandstone reservoirs were come from continuous miscible gas CO2 injection which contributed to an incremental Recovery Factor (RF) of about 34.5% for less than 10 years of production period. This fact has triggered many oil industries to apply this potential and proven technogy for their assets. This potential comes with the needs of having a robust tool to forecast additional recovery due to CO2 injection. This work focuses to development of predictive model using artificial neural network (ANN). More than 6000 series of input-output parameters for ANN training and validation/testing data are extracted from numerical reservoir simulator of 1/8 of five-spot pattern models. The models are set as combination of reservoir geometry, rock, fluid and well operating condition parameters within the range of CO2 EOR screening criteria. The main objective of this work is to find the best ANN architecture/model which accurately matches reservoir simulation results, especially the relationship of RF, total volume of injected CO2 (GI) and the reservoir characteristics and well operating conditions. Trial and error of ANN architectures and parameters are done on number of hidden layers, number of neurons for each hidden layer, learning rate (LR) value, and momentum constant (MC) with minimization algorithm (Lavenberg-Marquardt) in Feed-Forward Back Propagation (FFBP) schemes under log-sigmoid transfer function. An optimum result of ANN model is achieved with an architecture of 18-26-11-2. The relative error of RF and GI of the ANN model are within range of 3 to 10% respectively. A better average relative error of RF and GI of 2.8% and 4.15% respectively are obtained after removing the outliers (unrealistic combinations of input data) from training process of the ANN model. Furthermore, it is clearly found that oil viscosity plays the most the important factor in CO2 EOR method.
Aidagulov, Gallyam (Schlumberger Dhahran Carbonate Research Center) | Gwaba, Devon (Schlumberger Dhahran Carbonate Research Center) | Kayumov, Rifat (Schlumberger Middle East S.A.) | Sultan, Abdullah (King Fahd University of Petroleum and Minerals) | Aly, Moustafa (King Fahd University of Petroleum and Minerals) | Qiu, Xiangdong (Schlumberger Dhahran Carbonate Research Center, Now with Branch of Sinopec International Petroleum Service Corporation) | Almajed, Haidar (King Fahd University of Petroleum and Minerals) | Abbad, Mustapha (Schlumberger Dhahran Carbonate Research Center)
Carbonate reservoirs host a significant amount of hydrocarbon reserves in the Middle East and worldwide. In matrix acidizing stimulation, hydrochloric acid (HCl) is commonly injected into the well at pressures less than fracturing pressure to dissolve the carbonate rock and create high-conductivity channels, known as wormholes. Wormholes propagate through the damaged near-wellbore zone connecting the well with the reservoir. In this work, we aim to study the effects of pre-existing fractures on wormhole development.
Matrix acidizing processes were reproduced in controlled laboratory experiments where a 15% HCl solution was injected into a borehole drilled in a carbonate block sample containing pre-existing fractures, allowing the acid to penetrate radially into the rock sample. The experiment was conducted inside a polyaxial load frame to accommodate large block samples (20×16×16 in.). Prior to acid injection, the block was fully saturated with water and taken to 2,000-psi pore pressure and 4,000-psi confining stress to simulate downhole conditions. To evaluate the created wormholes, the tested block was cut open along the fractures followed by X-ray CT scanning of selected zones.
Here we report experimental results for matrix stimulation of one Indiana limestone block containing a series of parallel pre-existing fractures. Acid was injected at a constant rate through the 1-in. diameter borehole containing an 8-in.-long openhole section in the center of the block. Although the acid injection pressure was maintained below the pressure required to open the fractures, acid breakthrough was found to be governed by the pre-existing fractures. Indeed, unlike similar radial acidizing experiments in intact blocks, there were no indications of wormholes exiting the outer faces of the block. Moreover, the post-test evaluation of the central fracture along the openhole section clearly revealed the wormholes that etched the fracture faces. However, a closer look into the stimulated openhole section showed that the wormholes initiated in other directions inside the matrix as well. An X-ray CT scan of a 4-in. diameter cored borehole regions allowed us to compare the density and characteristics of the wormhole growth along the fracture and into the matrix.
Although radial acidizing experiments describe more closely real conditions of matrix acidizing, few cases have been published, particularly for large-block experiments. The large-scale block experiments presented in this study provide new insights on the impact of pre-existing fractures on wormholing mechanisms.
The gas deviation factor (Z-factor) is an effective thermodynamic property required to address the deviation of the real gas behavior from that of an ideal gas. Empirical models and correlations to compute Z-factor based on the equation of states (EOS) are often implicit, because they needed huge number of iterations and thus computationally very expensive. Many explicit empirical correlations are also reported in the literature to improve the simplicity; yet, no individual explicit correlation has been formulated for the complete full range of pseudoreduced temperatures and pseudo-reduced pressures, which demonstrates a significant research gap.
Jin, Yan (China University of Petroleum at Beijing) | Jin, Guodong (Baker Hughes, a GE Company) | Syed, Shujath Ali (Baker Hughes, a GE Company) | Jin, Miao (China University of Petroleum at Beijing) | Hussaini, Syed Rizwanullah (King Fahd University of Petroleum and Minerals)
Subsurface unconventional shale samples are always scarce. Outcrop analogs are often used as an alternative to enhance the understanding of the corresponding reservoir formation. One assumption is usually made that rock composition and properties between the outcrop and subsurface samples remain the same or similar, despite differences in their burial and diagenetic histories. This paper presents a comparative case study to investigate the similarities and differences in rock properties between outcrop and subsurface samples from the same formation.
Two subsurface and two outcrop samples from the Lower Silurian Longmaxi formation in Sichuan Basin of China were characterized to determine their mineralogical, geochemical, petrophysical, elastic and mechanical properties. Micro-CT images showed that one subsurface sample was drilled normal to the bedding, while other three samples were parallel to the bedding. Two subsurface samples differ in their mineralogy – the horizontal sample is clay-dominant, while the other one is predominantly comprise of quartz, dolomite and calcite minerals, very similar to two outcrop samples. All four samples are thermally immature and their Tmax is less than 435 °C. Subsurface samples have the highest TOC of 3.75% but relatively lower HI and OI. Other pyrolysis parameters are very similar between subsurface and outcrop samples. All samples have very low porosity of less than 2.5% and permeability of less than 9 nD, although subsurface samples have a relatively higher value.
The discrepancy in mineralogical composition, especially the clay content, results in different elastic and mechanical behavior of outcrop and subsurface samples. The subsurface sample is highly anisotropic in both compressional and shear wave anisotropy due to the large amount of clay minerals, while one outcrop sample exhibits the strong shear wave anisotropy only and the other one is almost isotropic. Subsurface samples have lower values of Young's modulus, peak stress, Mohr-Coulomb failure parameters and unconfined compressive strength than outcrop samples.
Tariq, Zeeshan (King Fahd University of Petroleum and Minerals) | Mahmoud, Mohamed (King Fahd University of Petroleum and Minerals) | Abdulraheem, Abdulazeez (King Fahd University of Petroleum and Minerals) | Al-Nakhli, Ayman (Saudi Aramco) | Bataweel, Mohammed (Saudi Aramco)
The enormous resources of hydrocarbons hold by unconventional reservoirs across the world along with the growing oil demand make their contributions to be most imperative to the world economy. However, one of the major challenges faced by oil companies to produce from the unconventional reservoirs is to ensure economical production of oil. Unconventional reservoirs need extensive fracturing treatments to produce commercially viable hydrocarbons. One way to produce from these reservoirs is by drilling horizontal well and conduct multistage fracturing to increase stimulated reservoir volume (SRV), but this method of increasing SRV is involved with higher equipment, material, and operating costs.
To overcome operational and technical challenges involved in horizontal wells multistage fracturing, the alternative way to increase SRV is by creating multiple radial fractures by performing pulse fracturing. Pulse fracturing is a relatively new technique, can serve as an alternative to conventional hydraulic fracturing in many cases such as to stimulate naturally fractured reservoirs to connect with pre-existing fractures, to stimulate heavy oil with cold heavy oil production technique, to remove condensate banking nearby wellbore region, and when to avoid formation damage near the vicinity of the wellbore originated due to perforation. Pulse fracturing is not involved with injecting pressurized fluids into the reservoir, so it is also a relatively cheaper technique.
The purpose of this paper is to present a general overview of the pulse fracturing treatment. This paper will give general idea of the different techniques and mechanisms involved in the application of pulse fracturing technique. The focus of this review will be on the comparison of different fracturing techniques implemented normally in the industry. This study also covers the models developed and applied to the simulation of complex fractures originated due to pulse fracturing.
Greenhalgh, Stewart (King Fahd University of Petroleum and Minerals) | Al-Lehyani, Ayman (King Fahd University of Petroleum and Minerals) | Schmelzbach, Cedric (ETH Zürich) | Sollberger, David (ETH Zürich)
The bearing and elevation (azimuth and inclination) of a seismic event can be estimated directly from measurements at a single triaxial station. There are instances in which the angular resolution secured by triaxial polarization analysis is better than that obtained by beamforming with an extended scalar array. In these situations, one depends totally on understanding the inter-relationships between the triaxial records that make up a seismic wavetrain. There are many approaches to seismic direction finding (SDF). Monte-Carlo techniques of triaxial seismic direction finding seek to maximise signal power by examining the seismic wavefield in many rotated co-ordinate frames. There are variants on this approach, which entail null seeking in an inverse space. Instead of searching all possible directions for the one which best fits the polarization model of a single arrival, it is possible to carry out an eigen-decomposition of the (complex or real) covariance matrix formed from the three-component data. The eigenvector corresponding to the principal eigenvalue yields the polarization direction automatically, with significant savings in computational effort.
Numerical experiments undertaken for different levels of random noise superimposed on a pure mode signal show that there are no significant advantages in using the Monte-Carlo techniques over eigendecompsoition. Confidence measures of event detection may be obtained by examining eigenvalue ratios when using the eigendecompsoition method. A time-domain formulation (covariance or coherency matrix) is preferable to a frequency-domain formulation (cross-spectral matrix) when there are multiple transient events present. The analysis window should be as long as possible (at least half the dominant period of the signal) without causing separate events to interfere.
In practise, the direction-of-arrival estimates deteriorate with increasing levels of random noise, and are generally unacceptable for a SNR of less than 1. Special care is needed to avoid direction errors associated with systematic noise, such as sensor gain misalignment between channels, coupling variations between receiver components, velocity inhomogeneity and anisotropy, the free-surface effect, and multiple event interference.
Al-Garadi, Karem (King Fahd University of Petroleum and Minerals) | Aldughaither, Abdulaziz (King Fahd University of Petroleum and Minerals) | Ba alawi, Mustafa (King Fahd University of Petroleum and Minerals) | Al-Hashim, Hasan (King Fahd University of Petroleum and Minerals) | Sibaweihi, Najmudeen (King Fahd University of Petroleum and Minerals) | Said, Mohamed (King Fahd University of Petroleum and Minerals)
Condensate banking has been identified to cause significant drop in gas relative permeability and consequently reduction of the productivity of gas condensate wells. To overcome this problem, hydraulic fracturing has been used as a mean to minimize or eliminate this phenomenon. Furthermore multistage hydraulic fracturing techniques have been used to enhance the productivity of horizontal gas condensate wells especially in low permeability formation. Even though multistage hydraulic fracturing has provided an effective solution for condensate blockage to some extent as it promotes linear flow modes which will minimize the pressure drops and consequently improves the inflow performance considerably. However, this technique is very costly, and has to be optimized to get the best long-term performance of the multistage fractured horizontal gas condensate wells.
In this paper, multiple sensitivity analyses were conducted in order to come up with an optimum multistage hydraulic fracturing scenario. In these analyses, our manipulations were focused mainly on the operational parameters such as fractures half length, fractures conductivity using compositional commercial simulator. CMG-GEM simulator was used to investigate the different cases proposed for applying multistage hydraulic fracturing of horizontal gas condensate wells. The investigation began with a base case scenario where the fractures half-length were fixed for all stages with equal spacing between them. Then, six more fractures half-length patterns were created by introducing new approach where the well performance was studied if they are in increasing trend away from the wellbore (coning-up), or in a decreasing trend (coning-down). Well performance is furtherly addressed when the fractures half-length arrangements formed parabolic shapes including both occasions of concaving upward and downward. Finally, the last two patterns illustrated the effect of having the fractures half-length arrangements both skewed to the left and right on well productivity.
The investigation of the effect of changing the multistage hydraulic fractures half-length distribution patterns on the performance of a gas condensate well was conducted and resulted in parabolic up distribution pattern to be the optimum pattern amongst the other tested ones. It results in the highest cumulative both gas and condensate production. It also maintains the gas flow rate and bottom hole pressure more efficiently. The parabolic up distribution pattern confirms that the majority of gas production was fed by the fractures at the heel and at the toe of the horizontal drainhole which is in agreement with the flux distribution along the horizontal well.