Viscoelastic surfactants (VES) are essential components in self-diverting acid systems. Their low thermal stability limits their application at elevated temperatures. The industry introduced new VES chemistries with modified hydrophilic functional groups, which enhances their thermal stability. These new chemistries are still challenged by the lack of compatibility with corrosion inhibitors (CI). This work aims to study the nature and the mechanism of the interaction between the VES and the corrosion inhibitors, which affects both the rheological and corrosion inhibition characteristics of the self-diverting acid system.
This study is based on rheology and corrosion inhibition tests, where combinations of VES and corrosion inhibitors are tested and complemented with chemical and microscopic analysis. Negatively charged thiourea and positively charged quaternary ammonium corrosion inhibitors were selected to study their impact on both cationic and zwitterionic VES systems. Each mixture of the corrosion inhibitor and the VES was blended in a 15 and 20 wt% HCl acid mixture, then assessed for its viscosity at different shear rates, CI concentrations, and temperatures up to 280°F in live and spent acid conditions. Each acid solution was assessed using Fourier-Transform-Infra-Red (FTIR) before and after each rheology and corrosion test to track the changes of the mixture functional groups. Each mixture was examined under a polarizing microscope to assess its colloidal nature. The corrosion inhibition effectiveness of selected acid mixtures was evaluated. N-80 steel coupons were immersed statically in the acid mixture for 6 hours at 150°F and 1,000 psi. The corrosion rate was evaluated by using metal coupon weight loss analysis followed by optical microscope examination for the metal surface.
The interaction between the CI and the VES surface charges and molecular geometries dictates both the rheological and the inhibitive properties of the acid mixtures. The use of a small molecular structure anionic CI with a cationic VES, results in a fine monodispersed CI particles in the VES-acid system. The opposite charges between the CI and the VES results in electrostatic attraction forces. Both the fine dispersion and the electrostatic attraction enhances the rheological performance of the mixture and packs the corrosion-inhibiting layer. The addition of a bulk and similarly charged CI with the VES results in a coarse polydispersed CI particles with repulsive nature with the VES. These properties increase the shear-induced structures and lower the packing of the inhibition layer deposited on the metal coupons, which decrease the rheological performance of the acid mixture and increase its corrosion rate. The FTIR analysis shows that there is no chemical reaction between the CIs and the VESs tested.
This work investigates the interactions between the corrosion inhibitors and the viscoelastic surfactants. It explains the impact of the surface charge of both corrosion inhibitors and VES on their rheological and corrosion inhibition characteristics. It adds a selection criterion for compatible VES and corrosion inhibitors.
Hydraulic fracturing has always been associated with significant volumes of fracturing fluid invading the formation matrix, which leads to water blockage and a reduction in relative permeability to gas or oil. In Shale and tight formations, this has become more challenging since capillary forces have profound impact on water retention and hence, water recovery and subsequent oil productivity. Surfactants and microemulsions have been extensively reported as flowback additives to lower surface and interfacial tension to maximize water recovery.
Most of the previous studies focused on a few testing methods to validate a surfactant or a microemulsion formulation for flowback use. In this work, a new environmentally friendly water-based surfactant formulation (Surf-I) was evaluated for flowback and its performance was compared against several industry standards of microemulsions and non-ionic alcohol ethoxylated surfactant. Surface tension (ST), interfacial tension (IFT), contact angle (CA), and coreflood tests were conducted in a wide range of typical field conditions of water salinity, temperature, crude oil type, and surfactant concentration. Core flow testing on 0.1-0.3 md Kentucky sandstone was conducted simulating oil reservoirs following constant-pressure flow schemes of 50-500 psi. Water recovery and oil productivity were determined for each pressure stage.
The new formulation showed a surface tension of 26 mN/m with CMC corresponding to a load of 0.1-0.3 gpt, depending on the water salinity. Interfacial tension measurements varied from 0.17 mN/m to 10 mN/m, depending on the crude oil type and temperature. Contact angle measurements indicated the surfactant ability to water-wet controlled substrates. The coreflood results confirmed the benefit of using surfactants for flowback versus non-surfactant cases, especially at low- to mid-pressure flow and. At 50 psi pressure difference, no oil was observed in the no-surfactant case. At 100, 250, and 500 psi the oil productivity with surfactant was 53, 22, and 20% higher than the base case. The results also showed that a formulation with ultra-low IFT (5E-2 mN/m), can initially recover substantial water volume but did not show a superior performance over the new formulation. The data obtained in this study can be used to identify the optimum criteria of a flowback additive in terms of surface tension, IFT, and wettability requirement to enhance water recovery and maximize oil productivity.
Surfactants have been used in the oil industry for decades as multi-functions additive in stimulation fluids. In hydraulic fracturing, surfactants and microemulsions have been extensively reported numerously as flowback additives to lower surface and interfacial tension to aid water recovery. Fracturing fluids invade the matrix during the fracturing, and if not recovered, leads to water blockage and a reduction to relative permeability to gas or oil. This problem is more challenging in low- permeability formations since capillary forces have more profound impact on water retention, and hence water recovery and subsequent oil productivity.
In this work, surface tension, interfacial tension, foam stability, sand-packed columns, and coreflood experiments were performed on a selected environmentally friendly water-based surfactant formulation. The performance of the surfactant of interest was compared to two commercial microemulsion and one non-ionic alcohol ethoxylated.
The results confirmed the benefit of using surfactants for flowback compared to non-surfactant case. Surface tension (ST) alone cannot be used as a selecting criterion for flow back. The alcohol exthoxylated, while reducing the ST to same level as the two microemulsions, showed very poor performance in packed column and coreflood tests. Although interfacial tension (IFT) seems to be more reasonable criteria, adsorption and emulsion tendency are other challenges that can hinder the performance of good surfactants with low IFT. Based on the data, a surfactant that lowers the IFT with the selected oil to below 1 mN/m is more likely to outperform other surfactants with higher IFT.
Pang, Mengqiang (Hohai University) | Ba, Jing (Hohai University) | Yu, Cun (Hohai University) | Zhou, Jian (Hohai University) | Wang, Enjiang (Hohai University) | Jiang, Ren (China Petroleum Exploration and Development Research Institute, Langfang Branch)
The attenuation (Q−1) of medium is a parameter more sensitive to pore fluid than seismic velocities for gas-bearing reservoirs, thus accurate estimation of seismic attenuation is very meaningful for exploration of natural gas reservoirs. In this paper, we used the quality factor to carry out the seismic identification of carbonate reservoirs and estimate the Q values point by point of the target layer by using S transform and improved frequency shift method. In addition, the two-dimensional Q profiles of some survey lines and the three-dimensional Q section of the whole area were extracted. The results show that the Q value is low in the gas-bearing area with high-porosity, and the attenuation is anomalously high. And in the non-gas-bearing area with low-porosity, the Q value is higher, with no attenuation anomaly. The analysis method of attenuation effectively reflects the absorption characteristics and gas-bearing differences of the stratum, and can be effectively used in reservoir prediction.
Presentation Date: Monday, October 15, 2018
Start Time: 1:50:00 PM
Location: Poster Station 5
Presentation Type: Poster
Zhou, Jian (Hohai University and University of Houston) | Ba, Jing (Hohai University) | Castagna, John P. (University of Houston) | Yu, Cun (Hohai University) | Jiang, Ren (RIPED-Langfang) | Ge, Qiang (RIPED-Langfang)
Seismic amplitude analysis could provide valuable information regarding physical properties of reservoir rocks that is related to seismic reflection characteristics, e.g. porosity. However, for thin-layer reservoirs, limited seismic resolution and related wavelet tuning often hinders accurate interpretation of seismic amplitudes. We show that for generalized simple layer, i.e. without the same magnitudetop and base reflections, amplitude of composite top-base reflection signal is affected by both perturbations to thinlayer reservoir and overburden rocks. The complex tuning behavior can be simplified using the fact that any arbitrary seismic signal can be uniquely decomposed using the Fourier transform into odd and even components that have distinct sensitivities to variation in thin-layer and overburdenproperties. Numerical analysis based on true log parameters in a tight-dolomite reservoir in the Sichuan Basin, China show that amplitude at peak frequency of the seismic data odd part (OAPF) is more sensitive to thin-reservoir porosity change compared to that of original signal (total waveform, TAPF) and even part of the waveform (EAPF). When applied in analyzing real seismic data, conventional TAPF is not obviously correlated to porosity variations. However, the OAPF attribute responds well to the porosity measured in boreholes, and also relates to apparent seismic attenuation. These results suggest that, for thin layers, amplitude-based interpretation and inversion may benefit from isolation of even and odd amplitude attributes.
Presentation Date: Monday, October 15, 2018
Start Time: 1:50:00 PM
Location: 209A (Anaheim Convention Center)
Presentation Type: Oral
Zhang, Ruxin (State Key Laboratory of Shale Oil and Gas Enrichment Mechanisms and Effective Development, and State Key Laboratory of Petroleum Resources and Engineering, China University of Petroleum) | Hou, Bing (State Key Laboratory of Shale Oil and Gas Enrichment Mechanisms and Effective Development, and State Key Laboratory of Petroleum Resources and Engineering, China University of Petroleum) | Zeng, Yijin (State Key Laboratory of Shale Oil and Gas Enrichment Mechanisms and Effective Development, Sinopec Research Institute of Petroleum Engineering) | Zhou, Jian (State Key Laboratory of Shale Oil and Gas Enrichment Mechanisms and Effective Development, Sinopec Research Institute of Petroleum Engineering) | Li, Qingyang (State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation, Southwest Petroleum University)
Traditional hydraulic fracturing requires lots of water and sand resulting in short fracture length and small SRV with a low production. However, a new waterless fracturing, called Liquefied Petroleum Gas (LPG) fracturing, is applied to stimulate shale formation effectively.
In order to figure out the mechanism of fracture initiation and propagation in LPG fracturing, four large-scale true tri-axial fracturing simulation experiments have been conducted on shale outcrops. Meanwhile, the effects of engineering factors, pump rate and fluid viscosity, on fracture propagation behavior in the shale formation are discussed.
The experimental results indicate that LPG fracturing not only activates discontinuities to form a complex fracture network, but also enhances induced fracture length to form a large SRV. Induced fractures have two initiation points, open-hole section and stress concentration point of wellbore wall, and have three main propagation behaviors, crossing, shear and arrest, dilation and crossing in shale formation. A low viscosity fracturing fluid activates discontinuities resulting in complex fractures, whereas, a high viscosity fluid would like to create some main fractures without opening discontinuities. Moreover, a high pump rate offers more energy for induced fractures to cross the discontinuities resulting in a long fracture length and large SRV. In addition, the anisotropic of shale formation and the existence of discontinuities cause signals attenuation, which increases the arrival time, resulting in location deviation of acoustic emission (AE) events in the AE monitoring. The pressure-time-energy curve, however, shows that the fracture initiation is earlier than the sample ruptured. That is, the initiation pressure is smaller than the ruptured pressure.
The experiments conducted in this paper prove that the LPG fracturing indeed has some advantages than traditional hydraulic fracturing, such as long fracture length and large SRV. And then, the research results provide the theoretical basis for the LPG fracturing operation in shale formation.
Zhou, Jian (State key Laboratory of Shale Oil and Gas Enrichment Mechanisms and Effective Development, Sinopec Research Institute of Petroleum Engineering) | Zeng, Yijin (State key Laboratory of Shale Oil and Gas Enrichment Mechanisms and Effective Development, Sinopec Research Institute of Petroleum Engineering) | Jiang, Tingxue (State key Laboratory of Shale Oil and Gas Enrichment Mechanisms and Effective Development, Sinopec Research Institute of Petroleum Engineering) | Zhang, Baoping (State key Laboratory of Shale Oil and Gas Enrichment Mechanisms and Effective Development, Sinopec Research Institute of Petroleum Engineering) | Shen, Boheng (Missouri University of Science and Technology) | Zhou, Jun (State key Laboratory of Shale Oil and Gas Enrichment Mechanisms and Effective Development, Sinopec Research Institute of Petroleum Engineering)
ABSTRACT: The multi-staged fracturing is becoming one of the key strategies for the shale gas development worldwide. The impact of stress shadow and natural fractures on fracture could cause unexpected fracture geometry in this case. The staged fracture initiation and fracture geometry during fracturing in shale are investigated through a series of tri-axial fracturing experiments. The shale blocks made by fresh shale outcrop were tested with a varied of perforation intervals as 80mm, 120mm, 160mm, 200mm, respectively. The testing results demonstrated that the multi-fracture interference occurred and it caused complex unbalanced facture geometry when the notch interval was 80mm and 120mm. By real-time diagnosis with microseismic(MS) data, we found that due to the double effect of stress shadow and natural fracture, the second fracture tends to be much shorter compared with the first fully developed fracture. Meanwhile, the direction of the second fracture tends to be a diverging fracture. However, the obvious effect of stress shadow was not found in our tests when the notch interval was 160mm and 200mm. At last, a simple mode for effective stimulation of reservoir volume (ESRV) calculation based on MS data was introduced to compare individual ESRV for different fracture geometries.
With the development of shale gas in the last decades, horizontal multi-stages hydraulic fracturing have more and more become valuable technique for stimulation of shale reservoirs. In naturally fractured shale reservoirs, the widely held assumption that the hydraulic fracture is an ideal, simple, straight, bi-wing, but planar feature is untenable because of natural fractures, faults, bedding planes and stress contrasts. In this kind of shale reservoirs due to interaction with natural fractures or frictional interface, the fracture may propagate asymmetrically or in multiple strands or segments.
The presence of natural fractures alters the way the induced fracture propagates through the rock. The early studies (Zoback, 1977; Daneshy, 1974; Lamont and Jessen, 1963; Blanton, 1982) have shown that the propagating fracture crosses the natural fracture, turns into the natural fracture, or in some cases, turns into the natural fracture for a short distance, then breaks out again to propagate in a mechanically more favorable direction, depending primarily on the orientation of the natural fracture relative to stress field. A fracture interaction criterion to predict whether the induced fracture causes a shear slippage on the natural fracture plane leading to arrest of the propagating fracture or dilates the natural fracture causing excessive leak-off was proposed based on mineback experiments (Warpinski and Teufel, 1987). A simple criterion for crossing was proposed by applying a first order analysis of the stresses near a mode I fracture impinging on a frictional interface oriented normal to the growing fracture (Renshaw and Pollard, 1995). According to their work, crossing will occur if the magnitude of the compression acting perpendicular to the frictional interface is sufficient to prevent slip along the interface at the moment when the stress ahead of the fracture tip is sufficient to initiate a fracture on the opposite side of the interface. Scaled laboratory experiments and numerical tests proved that high flow rate or viscosity yields fluid- driven fractures, while low flow rate just opens an existing fracture network (Beugelsdijk and de Pater, 2000, 2005). Laboratory scale tests also found that interaction of a hydraulic fracture with a natural fracture depended heavily on the stress state, inclination of the natural fracture with respect to the hydraulic fracture, and the strength of the natural fracture (Zhou et al., 2010 and Ingraham et al., 2016). For the case of natural fractures in shale are mineralized, researchers embedded planar glass discontinuities into a cast hydrostone block as proxies for cemented natural fractures and used these blocks to perform tests to examine the effects of cemented natural fractures on hydraulic fracture propagation. Their results show that obliquely embedded fractures are more likely to divert a fluid-driven hydraulic fracture than those occurring orthogonally to the induced fracture path (Olson et al., 2012).
Jiang, T. X. (Sinopec Research Institute of Petroleum Engineering) | Zeng, Y. J. (Sinopec Research Institute of Petroleum Engineering) | Zhou, Jian (Sinopec Research Institute of Petroleum Engineering) | Bian, X. B. (Sinopec Research Institute of Petroleum Engineering) | Shen, Boheng (Missouri University of Science and Technology) | Wang, H. T. (Sinopec Research Institute of Petroleum Engineering) | Hou, Lei. (Sinopec Research Institute of Petroleum Engineering) | Xiao, Bo (Sinopec Research Institute of Petroleum Engineering)
ABSTRACT: There are tremendous shale gas resources with depth of beyond 3500m in Sichuan basin, China. The tectonic stress is very high which causes an abnormally in-situ stress in this case, so that it brings challenges during horizontal staged fracturing, such as high breakdown pressure, low fracture complexity, low proppant concentration and weight, as well as less sufficient effective stimulated reservoir volume (ESRV) as expected. The research in this paper can improve the above situation. For achieving a better production in the shale formation, a new method of hydraulic fracturing technique was developed, including optimized perforation simulation, engineering solution for multiple scale fractures opening, the optimized propped method of multiple scale fractures, fracture height controlling. The simulation results demonstrated that the improving of fracture length, width and height is impressive which is 36%, 19% and 20%, respectively, after adopting 6 perforations in fixed plane perforation compared with 20 perforations in spiral perforation. In addition, the breakdown pressure was found to have an impressive decline after simulation by varied fluid viscosity from 200 mPa. s to 2.5 mPa. s. After adopting a combination of above work, the optimized design method has been applied in two wells for shale gas exploration.
1. BACK GROUND
The deep shale gas resource was tremendous in China (Chen zuo et al., 2016), only in some districts located in Sichuan basin, it was estimated that there was about 4612×108m3 shale gas resource (Dong Dazhong et al., 2012) with buried depth more than 3500 m. Compared with that in shallow or middle depth of shale gas wells, the characteristics of geology and hydraulic fracturing are listed as following (Dehua zhou et al., 2014; Haitao Wang et al., 2016).
Friction reducers (FRs) represent an essential component in any slickwater-fracturing fluid. Although the majority of previous research on these fluids has focused on evaluating the friction-reduction performance of chemical components, only a few studies have addressed the potential damage these chemicals can cause to the formation. Because of the polymeric nature of these chemicals—typically polyacrylamide (PAM)—an FR can either filter out onto the surface of the formation or penetrate deeply to plug the pores. In addition, breaking these polymers at temperatures lower than 200°F remains a problem. The present study introduces a new FR that replaces the linear gel with an enhanced proppant-carrying capacity and reduced potential for formation damage.
Friction-reduction performance, proppant settling, breakability, and coreflood experiments using tight sandstone cores at 150°F were conducted to investigate a new FR (FR1). The performance of the new FR was compared with two different FRs: a salt-tolerant polymer that is a copolymer of acrylamide and acrylamido-methylpropane sulfonate (FR2), and a guar-based polymer (FR3). Different breakers were used to examine the breakability of the three FRs, including ammonium persulfate (APS), sodium persulfate (SPS), hydrogen peroxide (HP), and sodium bromate (SB).
The friction reduction of the new chemical was higher than 70% in fresh water or 2 wt% potassium chloride (KCl) in the presence of calcium chloride (CaCl2) or choline chloride. The presence of 1 lbm/1,000 gal of different types of breakers did not affect the frictionreduction performance. The friction reduction of 1 gal/1,000 gal of the new FR1 was also higher than that of the guar-based FR3 at a load of 4 gal/1,000 gal at the same conditions. The results show that the new FR is breakable with any of the tested breakers. Among the four tested breakers, APS is the most-efficient breaker. Static and dynamic proppant-settling tests further indicated a superior performance of FR1 for proppant suspension compared with a PAM FR (FR2). Coreflood experiments showed that FR1 did not cause any residual damage to the core permeability when APS was used as a breaker, compared with 10% and 9% damage when FR2 and FR3 were tested, respectively. Coreflood tests also showed that FR1 is breakable using SB with only 2.5% damage, whereas FR2 and FR3 resulted in 47% and 41% damage, respectively. The results also show that higher salinity does not affect the breakability of the new FR.
The proposed FR shows higher friction-reduction performance and better proppant-carrying capacity with no formation damage, compared with the conventional counterparts. Hence, FR1 is a viable choice for application in fracturing formations with proppants.
Correlations between isofrequency amplitude traces from spectral decomposition provide a means of finding frequency notches induced by thin layers. Isofrequency traces tend to be strongly correlated between frequencies at spectral nulls; and amongst those that are not at those frequency notches. Spectral principal component (PC) amplitude attributes take advantage of this property, and are indicative of layer thickness. With proper trace scaling and spectral balancing, spectral PC amplitudes are independent of layer reflection coefficients. Layers with only odd and even pair reflection coefficients have distinctive spectral PC-thickness relationships in synthetic wedge models. Three spectral PC attributes individually delineate amplitudes from: 1) an isolated reflection not affected by tuning; 2) tuning of an even reflection pair; and 3) tuning of an odd reflection pair in a 3-D synthetic turbidite model.
Presentation Date: Tuesday, September 26, 2017
Start Time: 11:25 AM
Presentation Type: ORAL