This course deals with the basic theory that forms the foundation of simulators: mass balance and energy balance, black oil vs. compositional models, fractured reservoirs PVT data, gridding, well modeling and solution of linear and nonlinear equations. This will be done without any partial differential equations and it will require participants to have a mathematical background at the undergraduate level. The primary objective of this course is to reveal, in simpler terms, the fundamentals of reservoir simulators and how they impact users. The assumptions made in different types of models and their impact will also be discussed. In the end, this course is intended to make attendees more informed users of simulators.

Summary

The rotating disk apparatus (RDA) is used to study reaction kinetics. However, the current equations used to interpret the results from the RDA make oversimplifying assumptions. Some of these assumptions are not met in practice, yet no work has been done to study their impact on the mass transfer of the proton (H⁺) to the disk. The objectives of the current work are threefold: study flow regimes under the rotating disk in the RDA for Newtonian and non-Newtonian fluids, investigate the impact of the reactor boundaries on the mass transfer of H⁺ to the disk in Newtonian fluids, and identify the dimensions of the reactor that minimize this impact.

The mass transfer of the H⁺ was compared between different dimension reactors. Contrary to information reported in the literature, both the diameter of the reactor and the axial distance between the base of the disk and the bottom of the reactor have an impact on the rate of mass transfer of H⁺ to the disk. Moreover, the velocity profiles in the reactor showed three flow regimes: fully axisymmetric, fully asymmetric flow, and intermediate flow. These different regimes varied depending on the axial distance between the base of the disk and the bottom of the reactor, the diameter of the reactor, the rotational speed of the disk, and the kinematic viscosity of the reacting fluid.

Two approaches were proposed for the application of CM during the primary production period in oil reservoirs (Soroush and Rasaei 2018). The first approach involves a pseudo-injectors method, which assumes that some of the producer wells are pseudo injectors with negative rates. A new term is introduced to the CM equation to include the aquifer contribution (Eq.

The application of chemical scale inhibitors (SI) in a squeeze treatment is one of the most commonly used techniques to prevent downhole scale formation. This paper presents a sensitivity analysis of the treatment design parameters, to assist with the automated optimization of squeeze treatments in single wells in an offshore field.

Two wells were studied with different constraints on total SI neat volume (V_SI) and total injected volume (V_T) including main pill and overflush volumes, followed by a field case squeeze optimization to demonstrate the sensitivity to lifetime and the cost function per treated volume of water. A purpose-designed squeeze software model was used to simulate the squeeze treatments and perform the sensitivity analysis. In the course of this optimization procedure, a "Pareto Front" is calculated which represents cases that cannot in principle be improved upon. An analysis of these results also shows that this Pareto Front can be generated by a semi-analytical method, as shown for the first time in this paper.

It was demonstrated at fixed values of V_SI and V_T (resulting in almost a fixed total cost for squeeze), the squeeze lifetime can be improved by increasing the scale inhibitor concentration in the main treatment slug; however, the increase in squeeze lifetime is greatly reduced at very high concentrations. Four generic scale inhibitors were used with different adsorption isotherms to validate these calculations. In cases where either V_SI or V_T is fixed, it is shown that the squeeze life does not monotonically increase by the other parameter and the cost function can be used to determine the optimum design.

Well squeeze optimization was performed and these recommendations were applied in the field. It was shown that a well-executed sensitivity study can prevent misleading results that miss the global optimum. A lesson learned was that the optimal designs entail injecting as much of the inhibitor as possible as early in the squeeze design as possible - provided formation damage effects are avoided. Also, our semi-analytical construction of the Pareto Front greatly helps to simplify and streamline the overall squeeze optimization process.

In oil and gas industry, scaling prevention is one of the most important problems. While with more aggressive drilling and exploitation, scale control for the unconventional scale under complex water chemistry becomes more challenging. There are more chances to encountering with high temperature, high pressure, high TDS and some unconventional scale conditions. The modeling of the sulfide scale is notoriously difficult due to the extremely low solubility and complex water chemistry. Thus, the thermodynamic data is rare for sulfide minerals. Metal-sulfide-bisulfide complexes bring a large uncertainty for scale prediction. Another challenge is scale prediction in brine with high TDS, especially with high calcium concentration. Thermodynamic data with common ions Ca²⁺ and SO₄^2- is needed to improve thermodynamic models. The objective of this paper is to extend our knowledge for these exotic scale solubility predictions with both experimental studies and model validation. Some remaining questions in Pitzer theory framework have been thoroughly reviewed and discussed to improve the scale prediction for iron sulfide and high calcium condition. The newly derived models are able to predict the saturation index (SI) within ±0.3 unit for iron sulfide and ±0.15 units for common sulfate scales, respectively. These developed models have been incorporated into ScaleSoftPitzer for practical use in the oil and gas production.

This work provides a preliminary study of solids adherence on the surfaces of a sliding-sleeve valve (SSV), aiming to mimic inorganic scaling process. SSVs assembled in production sites subjected to water flooding might suffer from scale deposits of barium sulphate. Scaling may result in production stops, production restriction and also heavy workover jobs, reducing project profitability. The simulation of the scaling formation process allows the observation of fouling hotspots and, shortly, it can become a powerful tool to increase the valves reliability in scaling-prone scenarios. In the present problem, a four-way coupled CFD-DEM technique simulates the liquid-solid two-phase flow considering the solids particles as precipitated of barium sulfate crystals. The Discrete Element method allows the evaluation of inter particles interactions, such as collision, friction and adhesion, accounting for relevant phenomena such as particulate agglomerates build-up and particles adhesion on surfaces. The fluid-particle interaction forces arise from the simulation of the flow field through CFD. The main motivation is to analyze the influence of particle granulometry over the fouling process, keeping constant the scale index. The size distribution follows a normal distribution and reducing the mean dimension (smaller particles) results in more particles within the domain. The increase in the number of particles stimulate the formation of particulate agglomerates, which adhere on the grooves and holes of the SSV. Furthermore, agglomerates of tinier particles are less permeable, which accentuates the increase of the pressure drop in the valve.

Calcite (CaCO₃) is one of the most common scales in oilfield, and its formation can cause a decrease in production. Pressure drop can cause the pH and calcite saturation index (SI) to increase, similarly increase in temperature increases calcite SI. We have developed a new approach to simulate the water composition (e.g., TDS, Ca, and alkalinity) for laboratory tests with ScaleSoftPizer (SSP) software based on desired temperature, pH, and SI. The evaluation of calcite formation and inhibition in the laboratory is also a challenge because the release of CO₂ gas increases the pH and saturation index (SI) of the solution, and must therefore be controlled. Accordingly, this study aimed to develop a new and well-controlled test method for calcite inhibition under simulated oilfield conditions (i.e., pH, SI, Ca/HCO₃ ion ratio). A new rapid kinetic turbidity method was developed in a closed system for calcite inhibition study. Good consistency was obtained for triplicate calcite nucleation and inhibition experiments, which demonstrated the reproducibility of the new method. Calcite nucleation experiments were conducted, and a new calcite nucleation model is proposed. The effect of acetic acid and inhibitors on calcite kinetics was also evaluated with this new method. This is the first time to accurately measure calcite inhibition under a broad range of production conditions, especially under neutral-to-acidic conditions (pH = 5.5-7), using simple and low-cost kinetic turbidity test methods. By avoiding the release of CO₂, this new laboratory test method strictly controls pH, SI, and Ca/HCO₃ ion ratios, and thereby the field conditions for calcite scales can be accurately simulated. In addition, barite inhibition experiments were conducted, and inhibition models for eighteen different inhibitors were determined and put onto a self-consistent algorithm, with many practical advantages: speed, reliability, internal consistency, and relative effectiveness for common conditions, to mention a few. Finally, a protocol has been developed to characterize the inhibition of essentially any new inhibitor, or combination, with minimal to no testing.

To originate a discussion, you may submit a comment to any paper that has been published in a current SPE peer-reviewed journal. Comments should be based on fact, not opinion. Comments are not peer reviewed. Authors are only allowed to submit a single discussion on a paper. Authors may not submit a comment to their own paper.

A nearly 70-year-old equation has become the cornerstone of a newly emerged approach to reservoir diag­nostics and well appraisal at two of the largest shale companies in the US. With many North American tight-oil producers overseeing low-price-driven shut-ins of horizontal wells, this devel­opment has become increasingly rele­vant. As wellhead prices rise and the shut-in population is brought back into the fold, a window of opportunity exists for operators to run late-life interference tests on wells they otherwise likely would not have planned for.

A nearly 70-year-old equation has become the cornerstone of a newly emerged approach to reservoir diag­nostics and well appraisal at two of the largest shale companies in the US. With many North American tight-oil producers overseeing low-price-driven shut-ins of horizontal wells, this devel­opment has become increasingly rele­vant. As wellhead prices rise and the shut-in population is brought back into the fold, a window of opportunity exists for operators to run late-life interference tests on wells they otherwise likely would not have planned for. One challenge though will be in select­ing the ideal testing model. Outside of the traditional approach­es, the Chow Pressure Group (CPG) has been proposed as a promising candidate and one that is advantageous to all but the most price-sensitive and resource-strapped operators of shut-in assets.