Novel In-Situ Gelled Acid System Based on Inorganic Nanoparticles

Gelled acid systems based upon gelation of hydrochloric acid (HCl) are widely used in in both matrix acidizing and fracture acidizing treatments to prevent acidizing fluid leak-off into high permeable zones of a reservoir. The gelled up fluid system helps retard the acid reaction to allow deeper acid penetration for hydrocarbon productivity enhancement. The in-situ gelation is typically achieved by using crosslinked polymers with the acid. Conventional in-situ crosslinked gelled acid systems are made up of polyacrylamide gelling agent, iron based crosslinker and a breaker chemical in addition to other additives, with the acid as the base fluid. However, the polymer-based systems can lead to damaging the formation due to a variety of reasons including unbroken polymer residue. Additionally, the iron-based crosslinker systems can lead to scaling, precipitation and or sludge formation after the acid reacts with the formation, resulting in formation damage and lowering of hydrocarbon productivity. In this paper we showcase a new nanoparticles based gelled acid system that overcomes the inherent challenges faced by conventional in-situ crosslinked gelled acid systems. The new system can work in 5 to 20 % HCl up to 300°F. The new system does not contain any polymer or iron based crosslinker that can potentially damage the formation. It comprises nanoparticles, a gelation activator, acidizing treatment additives along with HCl. The new in-situ gelled acid system has low viscosity at surface making it easy to pump. It gels up at elevated temperatures and pH of 1 to 4, which helps with diverting the tail end acid to tighter or damaged zones of the formation. We demonstrate that the viscosification and eventual gelation of the new system can be achieved as the acid reacts with a carbonate formation and the pH rises above 1. As the acid further reacts and continues to spend there by increasing the pH beyond 4, the gel demonstrates reduction of viscosity. This assists in a better cleanup post the acidizing treatment. Various experimental techniques were used to showcase the development of the nanoparticle based acid diversion fluid. Static and dynamic gelation studies as a function of time, temperature and pH are reported. The gelation performance of the new system was evaluated at temperatures up to 300°F and discussed in the paper. Comparative performance of different types of gelation activators on the gelation profile of the nanoparticles is evaluated. It is also shown that the gelation and viscosity reduction is entirely a pH dependent phenomenon and does not require any additional breaker chemistry, and therefore provides more control over the system performance. The novelty of the new gelled acid system is that it is based upon nanoparticles making it less prone to formation damage as compared to a crosslinked polymer based system.

A Non-Damaging Gelled Acid System Based on Surface Modified Nanoparticles

Gelled acid systems based upon gelation of hydrochloric acid (HCl) are used widely in acid stimulation treatments to prevent fluid leak-off into the high permeable zones of a reservoir. The gelled-up fluid system helps retard the acid reaction to allow deeper acid penetration for hydrocarbon productivity enhancement. Conventional in-situ crosslinked gelled acid systems are made up of polyacrylamide gelling agent, iron-based crosslinker, and a breaker chemical in addition to other additives, with the acid as the base fluid. The polymer-based systems can lead to damage to formation due to a variety of reasons including unbroken polymer residue. Additionally, the iron-based crosslinker systems can lead to scaling or precipitation after the acid reacts with the formation, resulting in formation damage and lowering of hydrocarbon productivity. In this paper, we showcase a new nanoparticles-based gelled acid system that does not contain any polymer or iron-based crosslinker that can potentially damage the formation. It comprises nanoparticles, a gelation activator, acidizing treatment additives along with HCl. The new in-situ gelled acid system has low viscosity at surface making it easy to pump. With increase in the temperature and as the acid spends there is a viscosity increase. The viscosification and eventual gelation of the new system can be achieved as the acid reacts with a carbonate formation. As the acid further reacts and continues to spend, the gel demonstrates reduction of viscosity. This assists in a better cleanup post the acidizing treatment. Various experimental techniques were used to highlight the development of the nanoparticle-based acid diversion fluid. The gelation properties of the acid system, as a function of acid strength and temperature, are investigated. Static and dynamic gelation studies as a function of time, temperature and pH are reported. It is demonstrated that the viscosification property is a function of pH and the gelation occurs in a pH widow from 1 to 5 pH units. The gelation performance of the new system is evaluated at temperatures up to 300°F. The effect of different types of surface modification chemistries on the gelation properties is investigated. It is also shown that the gelation and viscosity reduction is entirely a pH dependent phenomenon and does not require any additional breaker chemistry; and therefore provides more control over the system performance. The new gelled acid system overcomes the inherent challenges faced by conventional in-situ crosslinked gelled acid systems; as it is based upon nanoparticles making it less prone to formation damage as compared to a crosslinked polymer-based system.

In situ extraction (milking) of the two promising Botryococcus braunii strains Showa and Bot22 under optimized extraction time

In situ extraction or “milking” of microalgae is a promising approach to reduce downstream costs in order to produce low-value substances such as lipids from microalgae in an economical way. Due to its ability to secrete high amounts of long-chain hydrocarbons to an extracellular matrix, the green microalga Botryococcus braunii is suitable for the process of in situ extraction as the cost intensive steps of harvesting, dewatering, and cell disruption could be omitted. Based on a previous study investigating various B. braunii strains in terms of growth, lipid accumulation, and solvent compatibility, the B. braunii strains Showa and Bot22 (both B race) were identified as potential candidates for the process of in situ extraction. In order to prove the suitability of these two strains for the process of in situ extraction, this study first determined the optimal extraction time using short-term in situ extraction over 7 days at different starting biomass concentrations of 1.5 and 2.5 g L−1. Furthermore, both strains were treated applying the optimal extraction time in long-term in situ extractions for 30 days to confirm the results from the short-term extractions. The results indicate a strain-dependent optimal extraction time of 300 min day−1 for strain Showa and 200 min day−1 for strain Bot22. During long-term in situ extraction for 30 days, hydrocarbon productivity was 16.99 mg L−1 day−1 (10.53 mg gDW−1 day−1) for strain Showa and 14.53 mg L−1 day−1 (10.48 mg gDW−1 day−1) for strain Bot22. Furthermore, a direct correlation between hydrocarbon productivity achieved by in situ extraction and the hydrocarbon concentration in the biomass of the respective strain could be established. It could be shown that the consideration of the effective extraction time and the phase boundary area is required to calculate an extraction system independent value for the comparison of different extraction setups.

Optimization of Fracturing Parameters in Changning Shale Based on a New Comprehensive Multi-Factor Analysis Method

Horizontal well multi-cluster fracturing technology is the most effective technical approach to exploit unconventional reservoirs (such as shale). The hydrocarbon productivity after fracturing often depends on the selection of fracturing location and fracturing parameters. However, these influencing parameters are very diverse and coupled with each other. Numerical simulation methods and laboratory experiment methods are often complicated to reflect the nonlinear relationship. Therefore, this study develops a new multi-factor analysis method based on field data to explore fracturing parameters’ weights that affect the hydrocarbon productivity after fracturing. This method combined the grey correlation method and entropy weight method to establish a combined weight analysis model. This method can comprehensively evaluate the influence factors on the post-fracturing productivity and ensure the accuracy of the obtained results through a field test. In our study, the influence of geological and fracturing parameters on 50 horizontal wells in Changning Shale is analyzed using the new method. These 50 wells are from the same block but have different values of fracturing parameters. The analysis results show that the fracturing parameters’ weight rankings on the post-fracturing productivity are fluid injection intensity, injection sand intensity, cluster spacing, injection rate, stage length, and average pump pressure. The weight rankings of geologic parameters affecting post-fracturing productivity are total gas content, brittle mineral content, porosity, Young’s modulus, minimum principal stress, total organic carbon, Poisson’s ratio, and maximum principal stress. Our study provides a new means of analyzing the influential factors of the in-situ hydraulic fracturing. Also, it gives a helpful guide for the selection of fracturing parameters in Changning Shale.

Large-scale screening of natural genetic resource in the hydrocarbon-producing microalga Botrycoccus braunii identified novel fast-growing strains

Algal biofuel research aims to make a renewable, carbon–neutral biofuel by using oil-producing microalgae. The freshwater microalga Botryococcus braunii has received much attention due to its ability to accumulate large amounts of petroleum-like hydrocarbons but suffers from slow growth. We performed a large-scale screening of fast-growing strains with 180 strains isolated from 22 ponds located in a wide geographic range from the tropics to cool-temperate. A fast-growing strain, Showa, which recorded the highest productivities of algal hydrocarbons to date, was used as a benchmark. The initial screening was performed by monitoring optical densities in glass tubes and identified 9 wild strains with faster or equivalent growth rates to Showa. The biomass-based assessments showed that biomass and hydrocarbon productivities of these strains were 12–37% and 11–88% higher than that of Showa, respectively. One strain, OIT-678 established a new record of the fastest growth rate in the race B strains with a doubling time of 1.2 days. The OIT-678 had 36% higher biomass productivity, 34% higher hydrocarbon productivity, and 20% higher biomass density than Showa at the same cultivation conditions, suggesting the potential of the new strain to break the record for the highest productivities of hydrocarbons.

New Treatment for Improving the Productivity of Shale Reservoirs Using Thermochemical Fluids

Shale reservoirs are characterized with very low productivity due to the high capillary pressure and the ultra-low rock permeability. This article presents an effective treatment to improve the hydrocarbon productivity for shale reservoirs by injecting thermochemical fluids. In this study, several measurements were carried out to determine the effectiveness of the presented treatment. Coreflood, rate transient analysis (RTA), and nuclear magnetic resonance (NMR) measurements were performed. The gas productivity was estimated, before and after the treatment, utilizing the gas flowrates and the pressure drop across the treated rocks. The improvement in gas productivity due to thermochemical fluids was estimated by calculating the productivity index (PI) and the absolute open flow (AOF) before and after the chemical injection. Also, the changes in the pore size distribution, due to chemical injection, were studied using NMR measurements. Results showed that thermochemical treatment can improve the gas productivity by 44%, increase the AOF by 450%, and reduce the capillary pressure by 47%. Also, NMR measurements showed that fractures were induced in the shale rocks after the treatment, which will improve the shale productivity. Ultimately, this study introduces, for the first time, the use of thermochemical fluids to improve the hydrocarbon productivity for shale reservoirs.

Sedimentation-capacity model of the subsalt deposits of the Southern Urals and adjoining territories

The junction zone of the Caspian syneclise, the Russian Plate and the Pre-Ural trough is characterized by a complex structure. It has been studied in some detail during large-scale geological, geophysical, and drilling operations in the search for mineral deposits. Subsalt deposits are associated with the main prospects for the growth of hydrocarbon reserves in this region. This makes it important to rethink the available data and conduct scientific analysis to identify patterns of formation of sedimentary complexes and an integrated assessment of their possible hydrocarbon productivity by means of sedimentation modeling. The structure and history of the formation of five large sedimentary complexes: the Ordovician-Lower Devonian, the Central Middle Devonian, the Frasnian-Tournaisian, the Visean-Upper Carboniferous, and the Permian are considered in detail. For each complex, a structural-formational position and sedimentation conditions are determined, which should determine the hydrocarbon productivity of local objects. The revealed relationship between the conditions of carbonate sediments accumulation and their potential reservoir properties served as the basis for forecasting the productivity of regional natural reservoirs. The paper presents a generalized model of the formation of subsalt strata and the forecast of the spatial distribution of different facies deposits, which play the role of accumulating and preserving strata. The results obtained are applicable in the practice of oil and gas exploration in the region

New exploration strategy in igneous petroliferous basins – Enlightenment from simulation experiments

There are two kinds of relationships between magmatism and the generation of hydrocarbons from source rocks in petroliferous basins, namely: (1) simultaneous magmatism and hydrocarbon generation, and (2) magmatism that occurs after hydrocarbon generation. Although the influence of magmatism on hydrocarbon source rocks has been extensively studied, there has not been a systematic comparison between these two relationships and their influences on hydrocarbon generation. Here, we present an overview of the influence of magmatism on hydrocarbon generation based on the results of simulation experiments. These experiments indicate that the two relationships outlined above have different influences on the generation of hydrocarbons. Magmatism that occurred after hydrocarbon generation contributed deeply sourced hydrogen gas that improved liquid hydrocarbon productivity between the mature and overmature stages of maturation, increasing liquid hydrocarbon productivity to as much as 451.59% in the case of simulation temperatures of up to 450°C during modelling where no hydrogen gas was added. This relationship also increased the gaseous hydrocarbon generation ratio at temperatures up to 450°C, owing to the cracking of initially generated liquid hydrocarbons and the cracking of kerogen. Our simulation experiments suggest that gaseous hydrocarbons dominate total hydrocarbon generation ratios for overmature source rocks, resulting in a change in petroleum accumulation processes. This in turn suggests that different exploration strategies are warranted for the different relationships outlined above. For example, simultaneous magmatism and hydrocarbon generation in an area means that exploration should focus on targets likely to host large oilfields, whereas in areas with magmatism that post-dates hydrocarbon generation the exploration should focus on both oil and gas fields. In addition, exploration strategies in igneous petroliferous basins should focus on identifying high-quality reservoirs as well as determining the relationship between magmatism and initial hydrocarbon generation.

Computed-Tomography Measurements of Water Block in Low-Permeability Rocks: Scaling and Remedying Production Impairment

Summary Fracturing-fluid invasion into the rock matrix can generate water block that potentially reduces hydrocarbon production, especially in low-permeability reservoirs. Here, we experimentally investigate the dynamics of water block under different flow scenarios (i.e., without shut-ins) and rock permeabilities through multiple coreflood experiments. A computed-tomography (CT) scanner is used to obtain the saturation profile within the core throughout the experiment, while the overall hydrocarbon productivity is measured from the overall pressure drop across the core. On the basis of the saturation and pressure measurements, we interpret the potential physical mechanism regarding the productivity reduction from water block and its self-mitigation facilitated by the capillary imbibition. Our interpretation also matches the observed scaling with rock permeability and the optimal shut-in time.