Wang, Xin (Rice University) | Ko, Saebom (Rice University) | Liu, Ya (Rice University) | Lu, AlexYi-Tsung (Rice University) | Zhao, Yue (Rice University) | Harouaka, Khadouja (Rice University) | Deng, Guannan (Rice University) | Paudyal, Samridhdi (Rice University) | Dai, Chong (Rice University) | Kan, Amy T. (Rice University) | Tomson, Mason B. (Rice University)
Iron sulfide scaling is a severe problem in flow assurance and asset integrity in oil and gas and deep-water production. FeS scale control is challenging due to the extremely low solubility, fast precipitation kinetics and complexity of ferrous iron and sulfide chemistry. Despite the ubiquity of FeS, we have limited understanding about the kinetics and thermodynamics of iron sulfide. To address this problem, we have developed a reliable anoxic plug flow reactor using argon gas to remove oxygen and PIPEs or MES buffer to control pH. The FeS (mackinawite) solubility, precipitation kinetics and phase transformation were the focus of this study. The impact of temperature (25 – 90°C), pH (5.92 – 6.91), ionic strength (0.15 – 4.30 M), Fe(II) to S(-II) ratio, dispersant and chelating reagent have been investigated. It was found that mackinawite is always the first FeS precipitated and could be stable for a week. It was suggested that low pH, high temperature and low ionic strength could accelerate the FeS phase transformation. FeS precipitation is under diffusion control at pH lower than 6.1, which could be accelerated by high temperature and high ionic strength. But the precipitation kinetics would be faster at higher pH. Some evidence suggests the importance of neutral FeS(aq) species at pH 6 −7. A polymeric compound containing amide functional group showed a promising effect by controlling the FeS particle size and reducing FeS scale retention rate. EDTA showed satisfactory FeS scale inhibition effect, as well as reducing FeS scale retention and H2S corrosion rate.
Zhao, Yue (Rice University) | M. Sriyarathne, H. Dushanee (Rice University) | Harouaka, Khadouja (Rice University) | Paudyal, Samridhdi (Rice University) | Ko, Saebom (Rice University) | Dai, Chong (Rice University) | Lu, Alex Yi-Tsung (Rice University) | Deng, Guannan (Rice University) | Wang, Xin (Rice University) | Kan, Amy T (Rice University) | Tomson, Mason (Rice University)
Silica is ubiquitous in oil and gas production water because of quartz and clay dissolution from rock formations. Furthermore, the produced water from unconventional production often contains high Ca2+, Mg2+ and Fe2+ concentrations. These common cations, especially iron, can form aqueous or surface complexes with silica and affect the nucleation inhibition of other scales such as barite. Thus, it is important to investigate the silica matrix ion effects on barite scale inhibitors efficiency to evaluate inhibitor compatibility with silica and common cations in produced waters.
In this study, experimental conditions were varied from 50 mg/L to 160 mg/L SiO2 in the presence of Ca2+ (1,000 and 16,000 mg/L), Mg2+ (2,000 mg/L) and Fe2+ (10 mg/L) at 70°C and neutral pH conditions, all with a background of 1 M NaCl. Our laser scattering apparatus was used to study the effect of silica matrix ions on barite nucleation inhibition [
Although iron sulphide (FeS) scale is not as common as carbonate and sulfate scales, it is difficult to inhibit, especially at high temperature conditions, due to its low solubility and fast precipitation kinetics. Moreover, the complexity of FeS solution and solid phase chemistry makes FeS deposition and related issues difficult to be solved. This study is to identify more efficient and effective dispersants and inhibitors for FeS scale. Polyacrylamide (PAM), polyvinyl pyrrolidone (PVP), polyoxazoline (OX) and carboxymethyl cellulose (CMC), which are frequently employed during oil and gas production activities for various purposes, successfully prevented FeS particles from settling. CMC was the most effective to disperse FeS particles in brines and it can disperse FeS particles under the conditions of as high as 4M of ionic strength. The size of FeS stabilized with polymers remained in nano-scale. Polymers did not work as threshold inhibitors, but prevented particle growth. Phosphonates and carboxylate chelating agents were also tested for FeS scale inhibition. Diethylenetriamine pentamethylene phosphonate (DTPMP), ethylenediaminetetraacetate (EDTA) and nitrilotriacetate (NTA) successfully inhibited FeS nucleation greater than 90% in a given reaction time of 2 hours at 70 °C, based on the measurement of Fe concentration in filtered solution with 0.22 μm syringe membrane. NTA showed the best inhibition performance at pH 5.0 and all three inhibitors stopped FeS nucleation at a substoichiometric concentration of inhibitors to iron(II). EDTA performed better than NTA and DTPMP at pH 6.7 at about 10% excess of EDTA molar concentration over iron(II). As pH and saturation index (SI) increased, greater concentrations of inhibitors were required to inhibit FeS scale.
Scale formation that can hinder continuous oil production is a serious problem in oilfield. Among all common scales, barite and calcite are two of the most important scales. Scale inhibitors have been widely added to prolong the induction time of scales. This study evaluates the methods and previous inhibition models to measure and predict scale formation in the presence of phosphonate and polymer inhibitors under common brine conditions. Turbidity measurement with laser light was used accurately and quickly to measure the induction time, and good reproducibility can be achieved between different sources of inhibitors. By conducting a set of independent inhibition experiments, previous models were evaluated and the demand for model improvement was carefully pointed out. On the basis of these evaluations, new ScaleSoftPizer (SSP) model was proposed by incorporating all available data under various simulated oilfield conditions (4-175 °C). The new SSP barite inhibition model was more internally consistent, and the new SSP calcite inhibition model expanded the applicable temperature ranges. The new SSP model was incorporated into SSP 2019. To prove the application of new SSP model, the predicted minimum inhibitor concentrations (MICs) were compared with lab observations and field data, which shows good consistence and improvements. This study improved the prediction of MIC over wide ranges of temperature and inhibitor types, which can significantly reduce the expenses and efforts to solve scale formation problems.
Si, Xueqiang (Petrochina Hangzhou Research Institute of Geology) | Xu, Yang (Petrochina Hangzhou Research Institute of Geology) | Wang, Xin (Petrochina Hangzhou Research Institute of Geology) | Guo, Huajun (Petrochina Hangzhou Research Institute of Geology) | Li, Yazhe (Petrochina Hangzhou Research Institute of Geology) | Shan, Xiang (Petrochina Hangzhou Research Institute of Geology)
Sandstone can be divided into many types with reference to permeability and porosity. Some scholars and researchers have established criteria to classify tight sandstone by using porosity and permeability. Sandstone with permeability less than 1mD and porosity less than 10% could be called tight sandstone. Exploration and development of tight sandstone gas has become a hot spot of oil and gas exploration (Dai J. et al., 2002) in China. Quite recently, tight sandstone gas reservoirs of different scales have been discovered in the middle-lower Jurassic of Taibei Sag in Turpan-Hami Basin. The purposes of this paperare to analyze the texture and composition of the middle-lower Jurassic tight sandstones, investigate diagenesis type and reveal the influence of diagenesis on reservoir quality.
Gao, Rui (RIPED, CNPC& Key Laboratory of Reservoir Stimulation, CNPC) | Wang, Xin (RIPED, CNPC& Key Laboratory of Reservoir Stimulation, CNPC) | Yang, Zhen (Planning Department, CNPC) | Zhan, Qiang En (Planning Department, CNPC) | Zheng, Wei (RIPED, CNPC& Key Laboratory of Reservoir Stimulation, CNPC) | Liu, Ying (Planning Department, CNPC) | Yang, Li Feng (RIPED, CNPC& Key Laboratory of Reservoir Stimulation, CNPC) | Liu, Zhe (RIPED, CNPC& Key Laboratory of Reservoir Stimulation, CNPC) | Wang, Zhen (RIPED, CNPC& Key Laboratory of Reservoir Stimulation, CNPC)
Tight oil and gas reservoirs are characterized by strong heterogeneity, poor physical properties, low single well production, difficult development and others. The volumetric stimulation fracturing technology has become a key technology for the effective utilization of tight reservoirs. In the current fracturing optimization design, there are some limitations in simulating the true pattern of fracture propagations because the geological model is relatively simple and it is not necessary to consider the heterogeneity of reservoir plane. At the same time, the effect of large-scale and large-volume injection of fracturing fluid on formation permeability field cannot be neglected in the volume stimulation, and the coupling relationship between fracturing fluid loss and reservoir seepage is not considered in conventional productivity simulations so that the effective stimulated reservoir volume (SRV) cannot be calculated accurately. In this paper, a numerical simulation technology of fracturing based on rock deformation is introduced through theoretical analysis and field application. The effective SRV is analyzed quantitatively, and the optimization simulation method of volume stimulation parameters with the effective SRV as the evaluation objective is formed preliminarily, which guides the fracturing design of volume stimulation in tight oil blocks.
Wang, Xin (Key Laboratory of Reservoir Stimulation, CNPC Fracturing&Acidizing Technical Service Center, RIPED, CNPC) | Zhu, Qingzhong (PetroChina Huabei Oilfield Company) | Zheng, Wei (Key Laboratory of Reservoir Stimulation, CNPC Fracturing&Acidizing Technical Service Center, RIPED, CNPC) | Lu, Haibing (Key Laboratory of Reservoir Stimulation, CNPC Fracturing&Acidizing Technical Service Center, RIPED, CNPC)
China has abundant low-rank coalbed methane resources. The research object is the low rank lignite seams in Jiergalangtu Sag in Erlian Basin. The reservoir has low porosity and low permeability, and it has no natural productivity. The coal seams have a burial depth of 200-600 meters, thickness of 40-60 meters, and Ro of 0.32% to 0.47%. Borrowing the idea of well completion experience for the conventional low rank coal seams in the region, open hole cavity completion techniques were adopted in two wells, obtaining an output of only about 150 m3/d. The conventional active water fracturing was also tested in another well, and the output after fracturing was 200-300 m3/d. The effect of stimulation was very poor, which limited commercial exploitation activities in the region. This paper introduces two techniques to improve the effect of stimulation by improving induced fracture extension and supporting capacity in the coal seams, including the hydraulic blasting & grouting caving fracturing technique and the reverse compound fracturing technique, which were applied in two wells. A constant rate of production after fracturing reached 1,500-2,000m3/d, which was well above the lower limit output of economic exploitation in the region of 600m3/d. Exciting results were obtained. The exploration of these techniques is of great significance for low rank coalbed methane stimulation, which can help us to implement effective fracturing stimulation operation in low rank coal seams to obtain the best production effect.
Kan, Amy T. (Rice University) | Dai, Joey (Zhaoyi) (Rice University) | Deng, Guannan (Rice University) | Harouaka, Khadouja (Rice University) | Lu, Yi-Tseng (Rice University) | Wang, Xin (Rice University) | Zhao, Yue (Rice University) | Tomson, Mason B. (Rice University)
Numerous saturation indices and computer algorithms have been developed to determine whether, when, and where scale will form. However, scale prediction can still be challenging because the predictions from different models often differ significantly at extreme conditions. Furthermore, there is a great need to accurately interpret the partitioning of water (H2O), carbon dioxide (CO2), and hydrogen sulfide (H2S) between different phases, as well as the speciations of CO2 and H2S. This paper summarizes current developments in the equation-of-state (EOS) and Pitzer models to accurately model the partitioning of H2O, CO2, and H2S in hydrocarbon/aqueous phases and the aqueous ion activities at ultrahigh-temperature, ultrahigh-pressure, and mixed-electrolytes conditions. The equations derived from the Pitzer ion-interaction theory have been parameterized by regression of more than 10,000 experimental data from publications over the last 170-plus years using a genetic algorithm on the supercomputer DAVinCI at Rice University. With this new model, the 95% confidence intervals of the estimation errors for solution density are within 4×10–4 g/cm3. The solubility predictions of CO2 and H2S are accurate to within 4%. The saturation-index (SI) mean values for calcite (CaCO3), barite (BaSO4), gypsum (CaSO4·2H2O), anhydrite (CaSO4), and celestite (SrSO4) are accurate to within ±0.1—and for halite the values are within ±0.01—most of which are within experimental uncertainties. This model accurately defines the pH value of the production tubing at various temperature and pressure regimes and the risk of H2S exposure and corrosion. Furthermore, our model is able to predict the density of soluble chloride and sulfate SO2–4 salt solutions within ±0.1% relative error. The ability to accurately predict the density of a given solution at temperature and pressure allows one to deduce when freshwater breakthrough will occur. In addition, accurate predictions can only be reliable with accurate data input. The need to improve the accuracy of scale prediction with quality data will also be discussed.
Determination of the complete stress-strain characteristics of rock is an essential issue in rock mechanics and plays an important role in solving excavation problems. To reflect the whole damaging process, a three-dimensional damage-softening statistical constitutive model for rock was established based on the Weibull distribution of mesoscopic element strength and by adopting the Generalized Zhang-Zhu (GZZ) criterion as the distribution parameter. The GZZ criterion is a three-dimensional Hoek-Brown strength criterion taking account of the influence of the intermediate principal stress. The results from the model were compared with existing experimental data, indicating that the model is feasible to describe the mechanical behavior of brittle rock. The influence of the Weibull distribution parameters on the constitutive model was studied and the results were generally consistent with physical interpretations of the Weibull parameters. A computer program for this constitutive model was developed, providing an easy way for simulating true triaxial tests under different conditions.
During underground excavations, a situation can arise where the rock material surrounding the excavation has failed but the excavation, as a structure, remains stable (Tiwari and Rao, 2006). It has been suggested (Bieniawski, 1967) that the most effective way to study this problem is through determination of the complete stress-strain characteristics of rock. The study of damage-softening constitutive model for rock can reflect the damaging process and complete stress-strain relationship of rock and is an essential issue in rock mechanics.
In the study of damage-softening constitutive model for rock, Krajcinovic and Silva (1982) introduced statistical damage theory and established a damage-softening constitutive model for rock at a certain confining pressure based on distribution randomness of internal defects in rock materials and hypothesis of rock particles obeying Weibull random distribution. This model was further developed by Tang (1993) and Cao and Fang (1998). There is an important parameter, namely the distribution parameter of mesoscopic element strength in this model. Cao and Fang (1998) adopted the Drucker-Pager (D-P) criterion as this distribution parameter. Wang et al. (2007) introduced the classical Mohr-Coulomb (M-C) criterion into the statistical constitutive model of rock to improve the model accuracy in damage-softening and residual strength, and concluded that the use of D-P criterion normally produces larger damage zone and the classical M-C criterion is more suitable. Shi et al. (2011) used Hoek-Brown criterion as the distribution parameter and discussed the influence of Weibull distribution parameters and Hoek-Brown criterion parameters on the rock damage-softening constitutive model.
He, Yong (PetroChina Zhejiang Oilfield Company) | Jiang, Liwei (PetroChina Zhejiang Oilfield Company) | Chi, Lu (iRock Technologies) | Wang, Xin (Independent Consultant) | Chen, Qiang (iRock Technologies) | Roth, Sven (iRock Technologies) | Dong, Hu (iRock Technologies)
To reliably evaluate the petrophysical, geochemical, and geomechanical properties of an organic-rich shale formation in China, we integrated digital rock analysis (DRA) with conventional core data and well log interpretation. The objectives of this paper included (a) to create a complete and accurate formation evaluation model for Wufeng-Longmaxi shale gas formation by combining pore-scale (digital rock), core-scale, and log-scale data; (b) to accurately characterize the micro-scale pore space, rock matrix, and organic matters in this formation, and create 3D pore network models from core samples; and (c) to identify the geological and engineering sweet-spot along vertical wellbore.
For well log interpretation, we obtained Gamma Ray (GR), spectral GR, neutron, density, resistivity, sonic logs, and elemental spectroscopy logs in the wells. For core measurements, we performed static and dynamic geomechanical experiments on core samples. For DRA, we obtained multi-scale images of the organic-rich shale samples, using three-dimensional (3D) micro-Computed Tomography (CT), 3D Focused-Ion-Beam Scanning Electron Microscope (FIB-SEM), and high-resolution Back-scattered Electron (BSE) imaging. Mineralogical and elemental analysis was also obtained by QEMSCAN. We then quantified various petrophysical properties from the digital rocks, including organic/inorganic porosity, Total Organic Carbon (TOC), elemental concentration and mineralogy. Most of the obtained properties were cross-validated with log data. Furthermore, we extracted pore network models from the digital rocks to quantify pore connectivity, pore throat size distribution, organic pore radius distribution, … etc, to provide more micro-scale information within the rock. Next, we determined the origin of quartz and the cause of high natural gamma-ray sections in the formation, based on point-by-point elemental analysis on SEM images and geochemical analysis. At last, we investigated various geomechanical properties using digital rock, core and log data. We compared geomechanical properties from core experiments and logs, then performed sensitivity study by DRA.
Two vertical wells in Wufeng-Longmaxi shale formation were studied by the introduced workflow. The DRA, core, and log data were mostly in good agreement, confirming the reliability of these methods. When multiple logs showed discrepancies in TOC, DRA provided additional key information for judgment. Based on the obtained petrophysical, geochemical, and geomechanical properties, we accurately characterized the Wufeng-Longmaxi formation, predicted the shale gas sweet-spot along the wellbore, and provided suggestions for future operations of horizontal drilling and fracking in this formation.
The exploration and development of shale gas formations in China attracted extensive interests among Chinese national oil companies and international operators. However, it was extremely challenging due to the complex geological features of organic-rich shale formations in China. Furthermore, conventional methods of core analysis and well log interpretation were usually unreliable in these complex formations, and unable to illustrate micro-scale information in shale. The integration of DRA with conventional core and log analysis significantly improved formation evaluation in organic-rich shale formations in China, and can provide basis for future development decisions.