Beletskaya, A. (Schlumberger Moscow Research Center) | Ivanov, E. (Schlumberger Moscow Research Center) | Stukan, M. (Schlumberger Moscow Research Center) | Safonov, S. (Schlumberger Moscow Research Center) | Dinariev, O. (Schlumberger Moscow Research Center)
Design of acidizing job involves application of reactive flow modeling. Most of the existing research and commercial codes for reactive transport modeling are based on Darcy-scale continuum representation of porous media. Such kind of simulations requires application of tuning coefficients, which, if not chosen properly, lead to inappropriate design of acidizing job. To overcome this issue, we have proposed direct reactive flow modeling approach at a pore scale using exact pore geometry.
The approach developed in this work is based on the combination of principles of chemical kinetics/thermodynamics and density functional theory applied for hydrodynamics (DFH). Chemical reactions are introduced to hydrodynamic simulation within the framework of partial local equilibrium assumption.
In the current study, it is demonstrated that developed approach adequately describes dissolution of porous dolomite rock by solution of hydrochloric acid. Simulations have been performed using 2D model of dolomite granule, 2D model of porous structure and 3D model of Silurian dolomite microstructure. Upon acid injection, the geometry of a rock is gradually changing in the area of acid penetration. As a result of modeling of dissolution of dolomite non-porous granule by solution of hydrochloric acid it is shown that the rate of dolomite dissolution depends on the rate of fluid injection. The average rate of dissolution is increased from 0.07 to 0.23 kmol/(m3·s) with the increase of Péclet number from 0.28 to 46. Similar correlations for porous rock with exact geometry can be utilized for corrections of the reaction rate constants which are used in Darcy scale simulations. Developed approach allows to perform modeling of dissolution reactions at pore scale and paves the way for increasing the consistency between the models used in reactive flow modeling and pore structure features of real rocks which will lead to improvements in acidizing job design.
Method of propellant fracturing under low rate reaction in wellbore hole is common in Russia and abroad. Usage of low volume propellant and dependence of fracturing mechanism from chemical reaction rate are the main limitations of technology application efficiency. Significant increase of energy output could be achieved by application of liquid reactants injection in near wellbore zone. In the paper, physical and chemical factors influencing on chemical reaction rate in porous media and thus controlling the fracturing mechanismare analyzed.
In this paper, key aspects of constructing a hydrodynamic model of high-pressure air injection into Bazhenov source rocks were highlighted. Most of them are associated with the choice of pseudo-components of kerogen required to describe thermal decomposition and oxidation of kerogen and needed for construction of a kinetic model. Sensitivity analysis was carried out. As a result, high sensitivity of output to the change in the content of components reflecting the presence of kerogen in the formation and its participation in oxidation processes and thermal decomposition was confirmed.
Based on the above, a list of experimental studies was formulated, which must be carried out to determine the parameters of numerical simulation and to evaluate the effectiveness of the high-pressure air injection method.
High-pressure ramped temperature oxidation of kerogen was carried out. As a result, temperature profiles, gas composition, and volume of generated/displaced fluids were obtained. 24.8 g of water-oil emulsion were generated from 92 cm3 of rock. Kerogen in the sample was completely converted, which was confirmed by the results of conducted pyrolysis studies.
Hydrochloric acid (HCl) as a stimulation fluid of deep oil and gas carbonate reservoirs is very common practice in the industry. Using HCl acid during matrix acid treatment in carbonate acidizing has the limitations of; rapid tubulars corrosion, formation face dissolution due to fast uncontrolled reaction rate especially at high temperature reservoirs and low injection rates, and induced formation damage due to sludge formation in presence of crude oil with high asphaltene content. There is also a difficulty of using HCl in stimulating multilateral and horizontal wells due to its fast reaction with the reservoir rock. With the intensive care given to the environment in the 21 century, chelating agents were introduced as alternatives to HCl to alleviate the problems associated with HCl. GLDA (Glutamic acid diacetic acid) chelating agent was used previously to stimulate carbonate reservoirs at high pressure and high temperature (HPHT) conditions. GLDA was prepared in fresh water to stimulate these reservoirs.
In this paper, the effect of dilution using seawater on the reaction kinetics of low pH GLDA (3.8 pH) with different carbonate rocks under HPHT conditions was investigated using the rotating disk apparatus (RDA). The reaction experiments of GLDA solution with carbonate rocks in both fresh (GLDA/DI) and seawater (GLDA/SW) were carried out at the same conditions. Indiana limestone and Austin chalk carbonate rock samples were used to investigate the effect of rock facie on the reaction.
The reaction regime of GLDA chelating agent with calcite is identified to be mass transfer limited in both seawater and fresh water. Also the overall reaction rate and calculated diffusion coefficient showed a high dependency in the temperature. At 200°F and 1000 psi the diffusion coefficient calculated for the reaction of GLDA/SW with Austin chalk is an order of magnitude higher than the reaction of the same fluid with Indian limestone.
The reported diffusion coefficients can be used to simulate for the optimum injection rate required for stimulating high temperature carbonate formation. Highlighting the effect of porosity facies in the acid reaction with carbonate rock will lead to better understanding of the overall reaction of stimulation fluids with carbonate rocks of the same lithology but different porosity facies.
Kang, Kang (Mewbourne School of Petroleum and Geological Engineering, University of Oklahoma) | Abdelfatah, Elsayed (Mewbourne School of Petroleum and Geological Engineering, University of Oklahoma) | Pournik, Maysam (Department of Mechanical Engineering, University of Texas at Rio Grande Valley) | Shiau, Bor Jier (Mewbourne School of Petroleum and Geological Engineering, University of Oklahoma) | Harwell, Jeffrey (Chemical, Biological & Materials Engineering Department, University of Oklahoma)
Matrix acidizing is an extensively used stimulation technique to improve oil recovery in carbonate reservoirs. The interplay between transport and reaction of acid is highly affected by heterogeneity at different scales. The existing experiments and models have difficulties to capture effect of heterogeneities across pore-scale, core-scale and field-scale. The objective of this paper is to provide an efficient multiscale model using continuous time random walk approach to predict acidizing behavior at macroscopic scale considering the effect of microscopic scale heterogeneity.
Instead of solving traditional advection-diffusion-reaction equation (ADRE), the continuous time random walk (CTRW) incorporating with particle tracking (PT) is a probabilistic approach to model fluid transport in heterogenous porous media. Here, the CTRW-PT describes motion of acid particles as random spatial and temporal increments at pore scale which follow independent distributions whose characteristic probability density functions (PDF) are derived. The transport of acid particles is simulated by particle tracking first and chemical reaction is included using the midflight approach. CTRW-PT simulation yields macroscopic plume of acid which creates wormholes at core scale. The core-scale wormhole propagation at different injection rate and concentration agrees qualitatively with the experimental results. Nevertheless, CTRW-PT also demonstrates the effect of heterogeneity that may increase the minimum pore volume to breakthrough. Using CTRW-PT approach is more efficient than solving ADRE in large-scale modeling.
The utilization of CTRW-PT approach on acidizing modeling captures the wormhole propagation of hydrochloric acid in limestone cores. This probabilistic and stochastic approach provides an efficient way to model carbonate acidizing and one can consolidate the lab-scale understanding with field prediction to optimize the acidizing treatment design.
A detailed understanding of the composition of sour gas accumulations is essential for facility design and for production forecasting. Compositional data like H2S and CO2 contents, net sales gas volume and condensate gas ratio also form the basis for all project economics. The acquisition of high quality fluid compositions is therefore a priority in all sour gas well evaluations. For conventional gas accumulations, PVT analysis of down-hole or well-head samples provides accurate and representative compositions of reservoir fluids. But in many sour gas accumulations, like the Marrat in North Kuwait, the prediction of future production streams is a difficult task. H2S levels are highly variable and the ‘point measurements’ from MDT fluid samples may not be representative for the entire reservoir unit. This paper describes a new approach to derive gas compositions from the analysis of core samples so that PVT compositions can independently be verified and H2S concentrations can be extrapolated away from the down-hole sampling points. The method is illustrated with two wells from an ultra-sour gas field in the Arabian Gulf region.
Core and cuttings samples from gas reservoirs contain trace amounts of adsorbed gas and condensate, which can be thermally extracted. The desorbed fluids can then be analyzed using existing geochemical technology and the molecular compositions of the condensate can be used to derive the composition of the gas that was trapped in the reservoir. Carbon isotope ratios can be measured on the gas that is desorbed from core samples and provide a second, independent parameter to estimate the original gas composition. The obtained fluid distributions are used to reconstruct the filling history of the sour gas accumulation.
The isotopic signature of the gas, together with the composition of the organo-sulfur compounds in the condensate, allow the reconstruction of fluid compositions, which are a critical input parameter for the reservoir simulators. Combining the results from the geochemical analysis with existing PVT data allows the extrapolation of the fluid compositions and the reconstruction the field-wide compositional gradients.
With H2S and CO2 concentrations varying between 5 and 35%, the production forecasting of sour gas accumulations can be subject to large uncertainties. Reconstructing the gas compositions from core and cuttings samples with geochemical techniques substantially reduces these uncertainties.
A new laboratory work procedure has been developed to evaluate and test the performance and effectiveness of chemical-sealant-based loss circulation materials (CS-LCMs), which are often used in cases of severe-to-total losses. These unconventional testing methods should be useful tools to evaluate the integrity of loss circulation material (LCM) products under downhole conditions in terms of differential pressure buildup and how quickly such LCMs can arrest lost circulation.
Evaluation and testing of LCMs in the laboratory before field application are crucial. Conventionally, the plugging capacity of particulate LCMs is tested against various-sized slotted discs using a permeability plugging apparatus (PPA), and integrity is tested in terms of sealing capacity and fluid loss value. Testing the performance of CS-LCMs required another means that included plugging extra-large vugs and building a significant differential pressure that could sustain the drilling fluid column. Pumpability of CS-LCMs and mechanical strength performance over time were evaluated using a high-pressure/high-temperature (HP/HT) consistometer, ultrasonic cement analyzer (UCA), and modified PPA following this fit-for-purpose procedure.
Extensive laboratory testing revealed that the new testing method was highly compatible with almost all types of chemical-based LCMs, including resin, gunk squeeze, and thixotropic slurries. The effectiveness and performance of several commercially available CS-LCMs were measured using different vug sizes (i.e., up to tens of millimeters). Thickening time of LCMs were observed pumpable [i.e., <70 Bearden units of consistency (Bc)], even after hours of conditioning at bottomhole circulating temperatures (BHCTs). As per API routine practice, tested slurry is deemed unpumpable if Bc exceeds 70. However, the thickening time of gunk squeeze LCMs were observed to be significantly high in a short interval of time once aqueous and nonaqueous streams mixed together. Gunk-based LCMs build high differential pressures and compressive strength over the same periods of curing time at bottomhole static temperature (BHST) and pressure compared to thixotropic-based LCMs.
Appropriate laboratory testing and evaluation of chemical-based LCMs under downhole conditions are highly recommended before field trail/application. This new testing/evaluation method should help minimize operational risk and nonproductive time (NPT) at the rig site.
The detonation of explosives in the wellbore produces hazardous gas; however, these gases are not typically observed in high concentrations at the surface. Recently, during plug and abandonment (P&A) operations, carbon monoxide (CO) from perforation activities was observed in high concentrations. This paper examines these types of operations to determine root causes and mitigation methods.
The anticipated amount of CO produced by detonation is calculated by both the empirical equation and reaction-equilibrium simulation methods for cyclotetramethylene tetranitramine (HMX), as well as by the simulation method for cyclotrimethylene trinitramine (RDX), hexanitrostilbene (HNS), and 2,6-bis,bis-(pikrylamino)-3,5-dinitropyridine (PYX). The life cycle of this gas from the time of generation through its potential release to the surface is discussed with the intent to reduce its quantity or concentration throughout. Mitigation methods include the incorporation of an oxidizer in the explosive reaction, chemical scavenging in the wellbore, and controlled venting or catalytic conversion at the surface.
Significant quantities of CO are produced by perforating guns, with the proportion increasing for explosives of greater thermal stability until it is the single largest reaction product. During perforation, these gases are usually controlled by gas-handling equipment on the platform; however, the reduced availability of this equipment on the platform at the time of P&A operations is thought to be a contributing factor to the hazard. Another significant factor could be the use of a high circulation rate, which has the effect of increasing the concentration of the gas on the surface. Controlled venting, flaring, and catalytic conversion to carbon dioxide are feasible methods to help mitigate this hazard if conducted in accordance with regulations.
This paper details the life cycle of CO gas generated from perforating activities and discusses how it can be hazardous during P&A operations. In addition, several methods are discussed that can help mitigate this hazard.
Nedwed, Tim (ExxonMobil Upstream Research Company) | Kulkarni, Kaustubh (ExxonMobil Upstream Research Company) | Jain, Rachna (ExxonMobil Upstream Research Company) | Mitchell, Doug (ExxonMobil Upstream Research Company) | Meeks, Bill (ExxonMobil Development Company) | Allen, Daryl P. (Materia Inc.) | Edgecombe, Brian (Materia Inc.) | Christopher, J. Cruce (Materia Inc.)
Industry maintains well control through proper well design and appropriate controls and barriers. This has made loss of well control a very low probability event. Currently the final barrier to maintain control is a valve system (blowout preventer or BOP) located on top of wells capable of sealing around or shearing through obstructions that might be in the well (e.g. drilling pipe and casing) to isolate the well. Although the risk is low when proper drilling practices and design are employed, there are still concerns about well control especially for operations in sensitive environments. Adding an additional barrier could alleviate these concerns.
One scenario for well control loss is if the BOP fails to seal allowing drilling fluids and reservoir fluids to flow. We are currently evaluating a concept to respond to such an event and seal leaking BOPs by injecting a liquid monomer and a catalyst below a BOP leak point to form a polymer-plug seal.
Mixtures of dicyclopentadiene (DCPD) and other monomers mixed with a ruthenium-based catalyst cause a rapid polymerization reaction that forms a stable solid. These reactions can occur under extreme temperatures and pressures and withstand significant contamination from other fluids and solids.
Lab studies have shown that DCPD-based polymer plugs can withstand axial stress of 15,000 psi without significant deformation even at temperatures of 200°C and with 20% drilling fluid contamination. For well control, one option is to preposition monomer mixes and catalyst into pressurized cannisters located at or near subsea BOPs while drilling high-complexity wells. Connecting the pressurized cannisters to appropriate ports on the BOP will allow rapid transfer. During a well-control event, actuating valves would rapidly force the monomer mixes and catalyst from the cannisters into the BOP to initiate polymerization. Polymerization reactions can be as short as a few seconds depending on the monomer mix and catalyst. The resulting solid polymer plug will block the leak path to potentially seal the well.
This paper describes the concept details and summarizes the current status of research.
Increased surface area of reservoir rock due to the presence of clays and the catalytic impact of clays are known to enhance the in-situ combustion (ISC) performance. But the basics behind these mechanisms are still not known. In this study, we investigated the role of clays on ISC in microscopic scale.
Six one-dimensional combustion tube experiments were conducted on three different crude oil samples. The combustion performance of each crude oil was evaluated with two combustion runs; reservoir rock prepared with sand-oil and with sand-clay-oil mixtures. Each combustion tube test was evaluated in terms of cumulative oil production, combustion front propagation, and characterization of the produced oil samples. Activation energy and heat of combustion were calculated empirically. Quality of the produced oil samples was determined through viscosity measurements. Saturates, aromatics, resins, and asphaltenes (SARA) fractions of initial and produced oil samples were compared. To better understand the fuel formation mechanism, asphaltenes surfaces were visualized by a Scanning Electron Microscope (SEM) and SARA fractions with Fourier Transform Infrared (FTIR).
Combustion tube experimental results highlight that crude oil type affects the process performance the most. Clay presence in the rock expedited the combustion front velocity by increasing the oxygen utilization rate. Activation energy was reduced drastically with the presence of clays, however, the heat of combustion has not changed. Thus, the generated heat has been consumed more effectively with the presence of clays. Produced oil quality has been increased significantly in terms of viscosity, more viscosity reduction was observed with the presence of clays. Since saturates acts like an ignitor during ISC, the amount of saturates fraction was decreased in produced oil when compared to initial oil. While the amount of aromatics fraction was increased significantly, the asphaltenes fraction is decreased with the presence of clays when compared to the aromatics and asphaltenes fractions of the initial oil. The reduction in viscosity is mainly due to increased aromatics content of produced oil with high solvent power. With the SEM images taken on asphaltenes surface, the role of clays has been observed clearly on fuel formation. With the presence of clays, the asphaltenes surface have created cribriform structures. Without clays, asphaltenes surfaces were observed as smooth surface. Those holes should increase the surface area on asphaltenes surfaces and increase the effective transformation of asphaltenes into fuel.