Control Over the Fracture in Carbonate Reservoirs as a Result of an Integrated Digital Stimulation Approach to Core Testing and Modeling

2021 ◽  
Author(s):  
Alexey Yudin ◽  
Abdul Muqtadir Khan ◽  
Rostislav Romanovskii ◽  
Alexey Alekseev ◽  
Dmitry Abdrazakov
Keyword(s):  
Oil And Gas ◽  
Gas Production ◽  
Physical Models ◽  
Real Field ◽  
Fracture Geometry ◽  
Rock Interaction ◽  
High Resolution Data ◽  
Digital Revolution ◽  
Acid Fracturing ◽  
Core Samples

Abstract The oilfield industry is rapidly changing towards reduced CO2 emissions and sustainability. Although hydrocarbons are expected to remain the leading source for global energy, costs to produce them may become prohibitive unless new breakthrough in technology is established. Fortunately, the digital revolution in the IT industry continues at an accelerating pace. A digital stimulation approach for tight formations is presented, using the achievements of one industry to solve the challenges of another. The fracture hydrodynamics and in-situ kinetics model is incorporated in the advanced simulator together with the detailed multiphysics models based on acid systems digitization, including rheology and fluid- carbonate interactions data obtained from the laboratory experiments. Digitization of fluid-rock interaction and fluid leakoff was performed using a coreflooding setup that allowed pumping concentrated acids in core samples at high-pressure/high-temperature (HP/HT) conditions. Varying the testing parameters across a broad range allowed refining the model coefficients in the simulator to obtain high accuracy in the predicted results. The digital slot concept was used to validate physical models in an iterative experimental approach. The software proved efficient at providing validation of multiphysics models used together with advanced slurry transport in the simulator. The fine computational grid allowed accurate predictions of the fracture geometry, etched width, and channel conductivity, resulting in realistic well productivity anticipations. Since multiple fluid systems of the acid stimulation portfolio were digitized and incorporated into the simulator, it was possible to optimize complex acid fracturing designs in the real field operations that included retarded single-phase and multiphase acid systems, self-diverting viscoelastic acids, and fiber- based diverting systems. Several case studies from multiple areas and reservoirs from Caspian and Middle East areas have demonstrated extremely positive oil and gas production results with reduced acid volumes with the digital stimulation workflow compared to conventionally stimulated offset wells. The digital stimulation workflow brings a new approach to acid fracturing optimization based on an integrated cycle in which high-resolution data from several sources are processed by powerful computing capacities. Starting from digitizing acid reactions with the core samples, through digitized rheology and particle transport in multiphysics models, an advanced numerical simulator tailors an optimum design from a number of acid system options, pumping rates, additive concentrations, and stage volumes to achieve best geometry of etched channels inside a fracture.

scholarly journals Barium Sulfate Scale Removal at Low-Temperature

Geofluids ◽  
2021 ◽  
Vol 2021 ◽  
pp. 1-12
Author(s):  
Hany Gamal ◽  
Saad Al-Afnan ◽  
Salaheldin Elkatatny ◽  
Mohamed Bahgat
Keyword(s):  
Corrosion Rate ◽  
Barium Sulfate ◽  
Oil And Gas ◽  
Ethylenediaminetetraacetic Acid ◽  
Chelating Agent ◽  
Gas Production ◽  
Oil Field ◽  
Rock Interaction ◽  
Dissolution Efficiency ◽  
Diethylenetriamine Pentaacetic Acid

Precipitation of the scale in the oil and gas reservoirs, surface and subsurface equipment, and processing and production facilities is a big problem as it affects petroleum production. The scale precipitations decrease the oil and gas production and cause economical loss. Solving this issue requires an engineering investigation to provide a safe, efficient, and economic solution. Consequently, this study proposed a developed dissolver for barium sulfate scales, where two field-scale samples were collected from different locations. The compositional analysis for scale samples showed that sample 1 is 100% barium sulfate where sample 2 has 97.75% barium sulfate and 2.25% of quartz. The composition of the developed dissolver has diethylenetriamine pentaacetic acid (DTPA) as a chelating agent, oxalic acid, and tannic acids as an activator, nonionic surfactant, and water as the base fluid. The new dissolver was investigated with extensive lab tests to determine the dissolution efficiency, precipitation tendency for the dissolved scale solids, corrosion rate, and fluid-rock interaction. The obtained successful results indicated that the developed dissolver had a dissolution efficiency for two real barium scale samples as the results showed 76.9 and 71.2% at 35°C and 91.3 and 78.4% at 90°C for samples 1 and 2, respectively. The new solution has a great performance compared with common scale dissolvers in the oil field as hydrochloric acid, ethylenediaminetetraacetic acid, and diethylenetriamine pentaacetic acid. The developed dissolver showed a very low precipitation tendency for the scale dissolved solids (1.9 and 3.2% for samples 1 and 2, respectively) under 35°C for 24 hours. Without any additives of corrosion inhibitors, the corrosion rate was 0.001835 g/cm2 at 6.9 MPa and 100°C for 6 hours. Injecting the developed dissolver for damaged sandstone core sample with barite mud by flooding test showed a return permeability of 115%.

scholarly journals The composition of groundwater in Palaeogene and older formations in the Netherlands. A synthesis

2016 ◽  
Vol 95 (3) ◽  
pp. 349-372 ◽  
Author(s):  
Jasper Griffioen ◽  
Hanneke Verweij ◽  
Roelof Stuurman
Keyword(s):  
The Netherlands ◽  
Rock Salt ◽  
Oil And Gas ◽  
Shallow Groundwater ◽  
Gas Production ◽  
Background Concentration ◽  
Continuous Series ◽  
Offshore Area ◽  
Rock Interaction ◽  
Confined Aquifers

AbstractThere is increasing interest in the exploitation of the deep subsurface of the Netherlands for purposes other than conventional oil and gas production, such as geothermal energy, shale gas exploitation and the disposal of radioactive waste, so for technical and environmental reasons it is important to understand the composition of the deep groundwater. A synthesis has been made of almost 200 existing groundwater analyses for the Oligocene and older formations in the Netherlands. Three groundwater categories are considered: (1) deep oil and gas reservoirs, (2) deep, buried and confined aquifers and (3) shallower, semi-confined aquifers with or without outcrop areas nearby. No distinct water types are found but a continuous series, with Cl ranging from around 10,000 to 200,000 mg l−1: the highest concentrations are found in the reservoirs and the lowest in the semi-confined aquifers. The most saline brines are found in the northern onshore area and adjacent offshore area, where Permian and Triassic rock salt also occurs regionally in the subsurface. The groundwater is usually pH-neutral, saturated in carbonates and anaerobic. Anhydrite saturation occurs when the Cl concentration exceeds 100,000 mg l−1, and halite saturation occurs at Cl concentrations close to 200,000 mg l−1. Few tracer analyses have been done for δ2H–H2O, δ18O–H2O, δ37Cl, Br, Li and B, which makes a rigorous palaeohydrological interpretation impossible. Lithium and B may be controlled by water–rock interaction which makes them less suitable as tracers. Some of the analyses suggest that dissolution of rock salt plays a role in determining the salinity of groundwater for some deep wells in the southern part of the Netherlands, whereas other analyses suggest that evaporated seawater influences the salinity in the associated wells. Cation-exchange patterns and alkalinity to Ca ratios indicate that groundwater in the deep, buried and shallow, semi-confined aquifers is usually freshening. Six14C analyses of samples from the buried aquifers indicate an apparent age of at least 20,000 years. Six δ37Cl analyses of formation waters from reservoirs in South-Holland suggest diffusion of Cl from a brine towards fresher water, and the associated K and also Li concentrations further suggest that these brines are related to rock salt dissolution and are not the residue of evaporated seawater. The high Ca concentrations are enigmatic for the hypersaline formation waters in the reservoirs. A limited series of samples had been analysed for various trace elements. The median concentrations are similar to the seawater and Dutch background concentration limits for shallow groundwater, but maximum concentrations can be up to three orders of magnitude higher. In conclusion, the data synthesis shows that the composition of groundwater in reservoirs and aquifers of Palaeogene and older age varies strongly in salinity at the national scale. Presence of evaporite deposits and diffusive transport seem to play important roles in controlling the salinity. Many existing analyses have no or only a few tracer analyses, that even vary among the samples. A complete suite of analyses is needed to elucidate the hydrogeological and geochemical processes that control the groundwater composition.

scholarly journals Effect of Produced Sand Particles and Fines on Scale Inhibitor: A Review

2021 ◽  
Author(s):  
Uche Callistus Anyanwu ◽  
Gbenga F Oluyemi
Keyword(s):  
Oil And Gas ◽  
Oil And Gas Industry ◽  
Fine Sand ◽  
Gas Production ◽  
Irreversible Adsorption ◽  
Gas Industry ◽  
Oil And Gas Production ◽  
Rock Interaction ◽  
Theoretical Application ◽  
And Migration

Scale inhibitors are deployed as preventive and rejuvenation operation in oil and gas industry when production operations are under threat or menace of scale blockage. The application of scale inhibitors is carried out through a method known as squeezing. In general, the squeeze process is governed by inhibitor-rock interaction which is described by adsorption/desorption isotherm. Most reservoirs produce loose sand grains or fine sand which float and flow within the pore spaces along with the squeezed scale inhibitors. Hypothetical reports have shown that not all scale inhibitors pumped into the formation adsorb onto the formation rock. A number of factors (irreversible adsorption, pH changes, competing ions, concentration and temperature) have been considered to affect the adsorption and return profile of these scale inhibitors. This review work examines the performances of most common scale inhibitors used in the oil and gas production activities, theoretical application in reservoirs and how loose fine sand grains affect the adsorption and desorption characteristics of squeezed scale inhibitors. Additionally, presented were overviews of previous reports on fine sand production and migration of fine sands through formation pores in reservoirs.

Prediction of Reservoir Parameters Variation Based on Time-Lapse Seismic Survey

2012 ◽  
Vol 433-440 ◽  
pp. 6370-6374
Author(s):  
Gang Fang ◽  
Xiao Hong Chen ◽  
Jing Ye Li
Keyword(s):  
Oil And Gas ◽  
Time Lapse ◽  
Seismic Inversion ◽  
Gas Production ◽  
Physical Models ◽  
Seismic Survey ◽  
Dynamic Monitoring ◽  
Oil And Gas Production ◽  
Fluid Saturation ◽  
Unconsolidated Sand

Fluid saturation and pressure are two of most important reservoir parameters during oil and gas production scheme adjustment. A method to compute the change of fluid saturation and pressure with multi-parameters regression was presented based on time-lapse seismic inversion data. Rock physical models of unconsolidated sand rock reservoirs were determined according to the real field’s conditions to analyze how seismic attributes change with variation of reservoir parameters. The radial basis function artificial neural network which was trained by this model was used to predict saturation and effective pressure. The predicted results are of high consistency with reservoir numerical simulation, which provide valuable reference for reservoir dynamic monitoring.

scholarly journals Constraints on emissions of carbon monoxide, methane, and a suite of hydrocarbons in the Colorado Front Range using observations of <sup>14</sup>CO<sub>2</sub>

2013 ◽  
Vol 13 (1) ◽  
pp. 1609-1672 ◽  
Author(s):  
B. W. LaFranchi ◽  
G. Pétron ◽  
J. B. Miller ◽  
S. J. Lehman ◽  
A. E. Andrews ◽  
...  
Keyword(s):  
Carbon Monoxide ◽  
Fossil Fuel ◽  
Oil And Gas ◽  
Oil And Gas Industry ◽  
Gas Production ◽  
Top Down ◽  
Gas Industry ◽  
High Resolution Data ◽  
The North ◽  
Emission Ratios

Abstract. Atmospheric radiocarbon (14CO) represents an important observational constraint on emissions of fossil-fuel derived carbon into the atmosphere due to the absence of 14CO in fossil fuel reservoirs. The high sensitivity and precision that accelerator mass spectrometry (AMS) affords in atmospheric 14CO analysis has greatly increased the potential for using such measurements to evaluate bottom-up emissions inventories of fossil fuel CO2 (CO2ff), as well as those for other co-emitted species. Here we use observations of 14CO2 and a series of hydrocarbons and combustion tracers from discrete air samples collected between June 2009 and September 2010 at the National Oceanic and Atmospheric Administration Boulder Atmospheric Observatory (BAO; Lat: 40.050° N, Lon: 105.004° W) to derive emission ratios of each species to CO2ff. From these emission ratios, we estimate emissions of these species by using the Vulcan CO2ff high resolution data product as a reference. The species considered in this analysis are carbon monoxide (CO), methane (CH4), acetylene (C2H2), benzene (C6H6), and C3–C5 alkanes. Comparisons of top-down emissions estimates are made to existing inventories of these species for Denver and adjacent counties, as well as to previous efforts to estimate emissions from atmospheric observations over the same area. We find that CO is overestimated in the 2008 National Emissions Inventory (NEI, 2008) by a factor of ~2. A close evaluation of the inventory suggests that the ratio of CO emitted per unit fuel burned from on-road gasoline vehicles is likely over-estimated by a factor of 2.5. The results also suggest that while the oil and gas sector is the largest contributor to the CH4 signal in air arriving from the north and east, it is very likely that other sources, including agricultural sources, contribute to this signal and must be accounted for when attributing these signals to oil and gas industry activity from a top-down perspective. Our results are consistent with ~60% of the total CH4 emissions from regions to the north and east of the BAO tower stemming from the oil and gas industry, equating to ~70 Gg yr−1 or ~1.7% of total natural gas production in the region.

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