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Jian, Guoqing (Pacific Northwest National Laboratory) | Fernandez, Carlos A. (Pacific Northwest National Laboratory) | Burghardt, Jeff (Pacific Northwest National Laboratory) | Bonneville, Alain (Pacific Northwest National Laboratory) | Gupta, Varun (Pacific Northwest National Laboratory) | Garrison, Geoffrey (Altarock Energy, Inc.)
ABSTRACT Four fracturing fluids; water, CO2, CO2 with water, and CO2 with an aqueous solution of a CO2-reactive polymer, poly(allylamine) (PAA, 1wt%) were evaluated using a high-temperature true-triaxial fracturing apparatus and ½ foot side granite cubic samples. All three CO2-based fracturing fluids, CO2, CO2 with water, and CO2 with aqueous PAA fractured granite at higher breakdown pressures, high transient flow rates, and produce higher-conductivity fractures as compared to water. Additionally, faster pressurization rates with CO2-based fracturing fluids (obtained when fracturing at constant flow rate mode) are found to be associated with higher fracture conductivities. When partially saturating the rock sample with PAA solution followed by fracturing with CO2, the volume expansion caused by CO2-induced cross-linking of PAA leads to a faster pressure increase due to the associated stress generated and increase in viscosity. It was also found that CO2 as a fracturing fluid injected in hot dry rock (HDR) attain the highest fracture conductivity only when injected at very high flow rates, followed very closely by the CO2/PAA fracturing fluid system that generates fractures with, on average, similarly high conductivity values though independently of injection flow rate and using 1/6 of the mass of CO2 as compared to CO2 in HDR. Breakdown pressures were also similar for CO2 stimulation in HDR and CO2/PAA fluid system under identical injection flow rates. It is concluded that CO2 (when injected in HDR) and CO2/PAA are the fluids of choice for stimulation of granitic rock samples under the studied geothermal P/T conditions. CO2/PAA, however, offer the following three additional advantages; 1) it requires significantly lower volumes of CO2, 2) fracture permeability is independent of injection flow rate, and 3) the reversible (previously reported) viscosity increase is beneficial to transport proppants if they are ever developed enhanced geothermal systems. 1. INTRODUCTION Enhanced geothermal systems (EGS) are man-made reservoirs, created where there is hot rock but insufficient or little natural permeability or fluid saturation. In an EGS, fluid is injected into the subsurface under carefully controlled conditions, which cause pre-existing fractures to re-open, creating permeability. They (Lund et al., 2011, 2005; Lund and Boyd, 2016; Lund and Freeston, 2001) are considered an alternative to fossil energy for that is attractive both because it is renewable and generates few CO2 emissions. After accessing the hot rock via drilling operations, hydraulic fracturing is recognized as an efficient way to increase the permeability of hot rock and, as a result, the heat exchange efficiency. However, unlike in low temperature settings (below 120 °C), oil and gas reservoirs, to fracture hot rock, operators need advanced stimulation fluids and tools that can withstand the high temperature environments. For example, gellants such as xanthan gum used to increase viscosity and enable proppant transport in tight oil and gas recovery cannot withstand temperatures above 120 °C. It is then critical to develop fracturing fluids that can efficiently fracture hot reservoirs without undergoing degradation of their chemical components. As importantly, EGS fracturing operations require on average ten times the water (Bradford et al., 2014; Chabora et al., 2012) needed for tight oil stimulation operations. Therefore, research efforts have been also directed to develop alternative fluids that either reduce or completely replace water without impact in fracturing performance.
Summary When fluid injection is shut-off after a fracture stage has been pumped, the sudden change in injection rate leads to a pressure fluctuation called a water hammer. These pressure pulses are observed and available at no additional cost because the pressure and rate data are recorded for every shut-in during field treatments. This abundant field data is commonly ignored. In this paper, we show that this water hammer signature can provide diagnostic information on fracture geometry. We simulated the transient flow problem in a wellhead-wellbore-fracture system to match the water hammer signature, and the solution provides the fracture dimensions based on the resistance-capacitance-inertance (R-C-I) circuit analogy. The analysis of water hammer signatures has been applied to multi-stage hydraulic fracture treatments to show the effect of input parameters and stress interference between stimulation stages. Water hammer simulation also suggests an accurate method to estimate instantaneous bottom-hole shut-in pressure (ISIP). This ISIP estimation for multi-stage treatments clearly shows the impact of the inter-stage stress shadow effect when applied to multi-stage fracture diagnosis. Simulated results which include stress interference effects indicate variations in fracture dimensions. This analysis also shows that the net fracturing pressure, near-wellbore frictional pressure drop, and stress magnitudes are changed by the stress shadow in multi-stage fracture treatments. This work has demonstrated that water hammer simulations can provide valuable fracture diagnostic information which compliments other diagnostic methods such as microseismicity and long-term production. Intitletroduction A pressure pulse is created when the fluid flow in a pipe is suddenly shut-in. This fluctuation of pressure is called a water hammer signature. It is observed in many instances in the oilfield. When an offshore water injection well is shut down or pumping of fluid is shut in during hydraulic fracture treatment, a water hammer signature is almost always observed as shown in Fig. 1a. This pressure fluctuation originates from the momentum change of the fluid in the conduit when the fluid experiences a sudden change of flow rate in a confined system. This pressure pulse propagates through the wellbore up and down within a few seconds as shown in Fig. 1b, and attenuates over time (typically within a few seconds to nearly a minute, depending on the condition of wellbore, fluid, fracture, and reservoir).
Abstract Offshore A drilling program on North Raguba field in Libya has been suspended since the current well's performance in this area was not promising. Well Raguba E-97 in this area was not producing even several attempts such as acidizing, re-perforation and gas lift optimization has been performed. Petrophysics and core analysis show that the well has 4% porosity and expected very low permeability. This paper demonstrates a methodical approach in the implementation of hydraulic fracturing technologies on this well. Technical background of fracture design, execution, onsite DataFRAC* analysis which include Mini-Falloff technique to measure transmissibility as well as post job production evaluation were utilized to optimize the result. A brief analysis on pevious treatment performed in this area was also provided and has been used at the design stage. Mini-Falloff techniques has helped to confirm that even the reservoir has extremely low porosity but has adequate permeability to transfer the flow. Pressure analysis also shown a presence of natural fissures that has been connected by fracturing and contributed to the final production post treatment. The well flow from 0 to 850 bopd post fracturing treatment. Based on this result, client continue its drilling program and Field Development Plan for Raguba since fracturing technology is proven to be the best solution for this reservoir. Introduction Raguba field is located in the western fairway geological trend of Sirte Basin in Libya (central part of Sirte Basin).
Abstract This work discusses a field-based pressure profiling method which allows direct evaluation of two important indicators of hydraulic fracture treatment quality - the presence of multiple fractures and vertical coverage. Individual or groups of active perforations are systematically hydraulically isolated with a conventional dual packer assembly. Short-term pressure changes are measured with downhole memory pressure gauges and comparisons of the pressure response behavior of the isolated intervals are made. Methodology, field test results, and implications are presented in this paper. Field tests show two types of perforation pressure response. Data can show which perforations are connected to fractures and whether multiple fractures have been created. One response ranges from 0 to 2 psi/minute and the other ranges from 3 to 30 psi/minute. The pressure profile results are compared to, and are consistent with, less direct interpretations from production logs and tiltmeter fracture mapping. Introduction Classic hydraulic fracturing models (PKN, KGD, radial, and variants), that assume linear elastic fracture mechanics and single-plane fractures that originate and/or are contained in a single layer, often fail to capture observed field behavior. Several phenomena may cause "abnormal" fracture initiation and propagation. The fracture plane is supposed to be normal to the minimum principal stress. It has been postulated by almost every investigator in the field that in the overwhelming majority of petroleum applications, fractures are vertical and normal to the minimum horizontal stress. However, even in the simplest, albeit elegant, description of the state of stresses for a given depth, the only stress that remains unchanged over large areas is the absolute vertical. Decrease in the reservoir pressure, because of production-induced depletion, or increase in the reservoir pressure because of fluid injection, may alter the interrelationship among the stresses. Shallower reservoirs are particularly susceptible to such phenomena. In the process of original formation deposition, the well-known Poisson translation might have dictated a predictable relationship between vertical and horizontal stresses. However, subsequent geologic events such as glaciation, erosion, diagenesis and tectonic or geothermal phenomena may alter this relationship considerably. At an extreme, the minimum horizontal stress, presumed to be "locked in place", may become larger than the vertical stress and, thus, a hydraulic fracture becomes horizontal, lifting the overburden. In the past, the critical depth, above which horizontal fractures are created, was reported by many to be in the range of 0-1500 feet. However, it would not be difficult to envision far greater depths in highly overpressured, tectonically compressed, and/or lightly overburdened formations. More important is the case where a formation is near this critical depth and where a fracture plane, initially propagating normal to one stress may change course by 90 degrees and become normal to another stress. This change of direction can happen when the difference in the magnitudes of the two stresses is less than the net pressure of the propagating fracture. Fracture geometries such as these, one of which is referred to as "T"-shape, are not uncommon. For vertical fractures, in reservoirs approaching stress isotropy in the horizontal plane, the net pressure, added to the minimum horizontal stress may exceed the seating pressure of transverse natural fissures, causing excessive leakoff. In many cases, both the latter phenomenon and "T"-shape fractures may bring about a severe dehydration of the fracturing fluid slurry leading to premature screenouts. P. 251
Buenrostro, Adrian (Saudi Aramco) | Abdulkareem, Harbi S. (Saudi Aramco) | Noaman, Yousef M. (Saudi Aramco) | Driweesh, Saad (Saudi Aramco) | Shammari, Nayef (Saudi Aramco) | Palanivel, Maharaja (Halliburton) | Khalifa, Mohamed (Halliburton)
Abstract During the past two decades, fracturing stimulation has become a production driver for a much greater part of the oil industry worldwide. Because of the extensive reservoir formation types, fracturing scenarios widely vary from conventional to unconventional cases. Fracturing is one of the few options for commercial hydrocarbon production in some extremely tight reservoirs. Unfortunately, many of the tight formation scenarios achieve fracture inititation and/or extension only under extremely high pressure, thus frequently reaching mechanical forces close to the well completion limitations. Among the different techniques used, the controlled breakdown technique (CBT) helped significantly improve pump rates in some fracture initiation and injection conditions. This technique controls pressure, while considering the completion's mechanical limits. This paper discusses the process and appropriate conditions for CBT application and evaluates when it is convenient or even crucial to help enhance fracture initiation and development.