S.M. Chavez-Morales, J.A. Gonzalez-Guevara, T.R. Prieto-Sosa and J.G. Alva-Arroyo, PEMEX

Abstract

Mexico has important reserves of heavy and extra heavy oil. In 2015, the proven reserves of crude oil were 9.711 million barrels (MMb). Sixty two percent of that volume are related to heavy crude, twenty nine percent is light crude and nine percent is super light crude. Therefore, alternatives methods are expected to be used at early times for the exploitation of the vast amount of oil fields.

Mexico had its first successful case of the application of an improved thermal recovery process which was developed in an extra-heavy oil reservoir that it will be called ST. This extra-heavy oil field has an original oil volume of approximately 580 million of barrels. Its oil production started under cold production and then due to the poor results in terms of oil production, it was decided to continue with a Cyclic Steam Stimulation (CSS) program which had great success between the years 2008-2011. Based on the results, the CSS was massified into the whole field. From the beginning until now, it has produced around 70.6 MMB, with an injected steam volume of 17.4 MMB.

Currently, most of the wells that have been producing by CSS are on the fifth to seventh steam injection cycle. Due to the decrease in oil production and the substantial increase in water production, a pilot test with steam flooding injection was designed as the next step for the exploitation strategy. The steam flooding test was planned to increase the reserves of extra-heavy oil in Samaria Neogene and stop the drop of the production. Three potential areas were selected, and a pilot test was divided into three phases. The first phase was in a confined area with the goal of avoiding steam channeling. Due to the continuity of the layers, a lineal well arrangement was considered with two injector wells and five producer wells. This was chosen to develop uniform heating in the sand layer.

Numerical simulation was performed to generate an exploitation and monitoring plan. The first stage of the steam flooding pilot test started on May 2018. The preliminary results of the first stage are promising, with a cumulative oil production of 95,962 barrels up to date, this represents 96 % of the oil expected by that time. These results are in good agreement with the simulation model.

The next steps are to implement this process in the other two selected areas to increase the total recovery factor from 5% to at least 15% in Samaria Neogene field.

V.S. Scordo Paes De Lima, G.F. Villarroel, V. Lara, F. Schein, A. Therisod, P. Guillen, V. Serrano, A. Ruiz, A. Lucero and J. Juri

Abstract

After an 18%STOOIP incremental oil polymer pilot we have developed the surfactant-polymer (SP) formulation to recover the residual oil. The SP formulation has a viscosity more than 1.5 times greater than oil viscosity. The Grimbeek reservoir is a heterogeneous multilayer fluvial system with many surfaces of contact between high permeability and low permeability.

Increasing oil recovery because of induced flow from low permeability to high permeability driven by a high viscosity slug has been around for more than 30 years. This phenomenon occurs when there is higher pressure drop across a viscous slug.

Does the cross-flow mechanism (Sorbie2019) that increased the polymer flow recovery benefit the surfactant-polymer flooding? How is this mechanism affected by factors such, removal of residual oil, surfactant concentration, slug size, salinity changed, retention and injection strategy? To answer these questions, we construct a detailed surfactant model in a compositional simulator that captures the multiscale nature of the multiple surfaces of contact created by the fluvial depositional environment. This realistic representation of the subsurface poses challenges to the numerical methods in the compositional simulator.

Through modelling the fluvial geometry in a compositional simulator, our simulation reveals that the viscosity overdesigned of the surfactant-polymer formulation favours accessing to more residual oil. Starting from a black oil model, the work was divided into four main tasks. First, converting the BlackOil PVT Model to a compositional model, followed by creating trajectories and perforations in an unstructured grid that brings complexities to the typical well-tracking task to place wells in corner point grids. Third, the compilation of the historical production of oil and gas as well as the water injected and polymer. We automate the input deck using visual basic and Python scripts that now are useful for any source file. Based on them, we can propose the most suitable injection strategy.

This result indicates that when the geological setting is heterogeneous is better to increase formulation viscosity (it depends on the formulation, but this usually means to increase surfactant concentration) and avoid the typical EOR workflow of formulation optimization to reduces surfactant concentration.

Our simulation elucidates the efficacy of increasing the formulation concentration to reduce the slug size. And It improves our understanding of the interplay between viscosity and capillary forces. Also, we developed different scripts that allow us to easily obtain the dataset for our compositional simulator.

Ahmed Elgendy, ENI S.P.A.

February 19, 2021

Cap rock integrity and thermally induced fractures (TIF) are two key issues to be evaluated when dealing with CO2 sequestration projects. We will present the current status of geomechanical modelling strategy for CO2 disposal projects, the actual developments towards a single integrated modelling environment (CMG-GEM). The presentation shall include several comparisons (case studies):

1. ECL-ABAQUS Vs CMG-GEM for subsidence prediction (PUNQ-S3)
2. COMSOL Vs CMG-GEM for TIF evaluation (Perkins analytical model)
3. COMSOL Vs CMG-GEM for TIF evaluation (Real case study)

Geochemical investigation in CCS operation: a new perspective

In the framework of Carbon Capture and Storage (CCS), geochemical investigation plays an important role in the assessment of the main physical and the chemical phenomena occurring during and after the CO2 injection in sedimentary formations. To increase the reliability and specificity of the investigation a strong integration between experimental analysis and numerical modelling is nowadays mandatory. Under this theme we shall present:

1. An integrated workflow starting from real samples, couples lab activities and numerical simulations
2. Comparative analysis between PHREEQC-3 and CMG-GEM via 0D (batch) models
3. CO2 injection in 2D multi-layered radial model (including site-specific minerals)

P. M. Adrian, YPFB Chaco S.A., T. Simsovic, UPSA.

Abstract

The purpose of this research was to evaluate the hydrocarbon recovery feasibility by nitrogen injection in a naturally fractured reservoir.

First the field case study fluid was characterized by an EOS (Winprop), then, a Dual porosity (PSS) a numerical model was chosen as valid approach for the study due to missing special logging information. The reservoir was a Devonian sandstone with natural fractures, defined as a type A, according to Aguilera (2003) classification, with an extremely tight matrix (1x10^-3 md). This gas-condensate reservoir had an initial condensate-gas ratio of 46 bbl/MMscf with an OGIP of 375 Bscf. The reservoir did not presented pressure maintenance due to aquifer presence, however water channeling was observed in two of the seven wells. The field is located at 28 km of the gas plant, therefore it was difficult consider a dry gas (C1-C2) or CO2 injection to enhance condensate recovery. Nevertheless, N2 was an alternative option with a similar efficiency for gas-condensate reservoir. After performing a history match (production and pressure), it has been evaluated different scenarios of N2 injection such as: well location, injection rate, injection time start.

The effect of nitrogen channeling through the fractures network was the main problem to deal with, which was typical phenomenon in naturally fractured reservoir. To improve this production condition, a sensitivity analysis was performed on the injection rate, well location and injection start. As a result, it was observed that injection rate should be between 4% to 6% of the production rate, and that injection should begin a few years after production start, nevertheless before reservoir pressure fall below dew point pressure. In addition, the injector well should be as far as possible from the producing wells to delay the fluid channeling. Finally, only for some of the N2 injection scenarios, economic feasibility was attained.

Richard Velasquez

Abstract

The "Oficina" formation is the most important in the Eastern Venezuela Basin and represents the main target for this study, which is to optimize the oil production and increase well productivity by the means of reducing the oil viscosity through the application of downhole electrical heating cable. The main objective of this study is to investigate and quantify the effect of downhole electrical heating cable in the performance of the extraheavy oil reservoir and horizontal wells interaction by lowering the oil viscosity applying a coupled reservoir-wellbore simulation approach.

A fully integrated 3D reservoir and discretized mechanistic wellbore simulation approach is carried out in order to estimate downhole heating effect and interaction between reservoir inflow and wellbore performance during the heating inside the wellbore. Bottom hole pressure and temperature profile inside wellbore, productivity index, production fluid rates along horizontal well section are estimated under several sensitivities and optimization process including: heating rate, length and location of the cable inside wellbore. Numerical simulation is performed with commercially available thermal simulation software that has the feature of a wellbore modeling tool that can couple to the reservoir model. Additionally, optimization software is used to perform the sensitivity analysis studies and the automatic optimization of the heating rate, cable length and position.

The heating cable simulation approach allowed understanding the importance of considering wellbore heating parameters and the interaction of the highly viscous extraheavy oil in the reservoir by increasing the temperature inside the wellbore. By applying wellbore calculations coupled to the reservoir simulation, it was possible to understand critical aspects of the oil and gas flow in the reservoir due to different drawdown along horizontal well section, pressure losses along the wellbore due to friction and the general efficiency of the heating cable and consequences in oil production.

Bottom hole pressure, productivity index and production fluid rates along horizontal well section, were estimated under several sensitivities and optimization workflow including the heating cable parameters and location inside wellbore in order to estimate the additional cumulative oil production and increase of the productivity index and bottom hole pressure. Therefore, the dynamic model assessment permitted to define several criteria’s for well selection candidates and founded the basis for wellbore completion design and monitoring protocol program for pilot test in the Field.

Coupling wellbore reservoir simulation is more accurate when compared to a conventional numerical simulation approach since it was possible to conclude that location of the heating in the horizontal section and gas breakthrough could affects negatively the oil production of the wells due to gas expansion inside wellbore with temperature increase. Therefore, it is very important that heating cable assessment consider the fully integrated 3D reservoir and wellbore modeling.

Erika Trigos, Daniel Higuera, Eduardo Lozano. Mansarovar Energy.

Abstract

The main scope of this work was determining the viability of implement a steam flooding project in a Colombian stratified heavy oil reservoir with more than five stimulation cycles by well, where the wells have a current spacing of 10 acres.

A sector model of an area of 379 acres was used in this work. The paper includes history matching methodology, infill project evaluation, selection of objective sands by patterns, optimization of injection rate strategies according to the objective sands and selection of the pattern type. The history matching stage include determine the properties with major uncertainty and a brief sensitive analysis of these properties. The infill project evaluation includes the estimation of interference between wells and basic curve production reduction when spacing is reduced from to 5 acres and to 2.5 acres.

It obtained that the more recommendable pattern to be apply on the study field is the five-point patterns with a reduction of the steam injection on the time. A first scheme of steam injection was developed using sub-model for each objective sand; after that, the steam rate was tuning in the sector model using the Oil Steam Rate (OSR) like a control parameter. With the steam flooding project, it hopes an incremental oil recovery factor from 10 % to 20% according to the injected sands. The cumulative oil steam rate at the end of the project is higher than 0.25.

This paper present additive information about the steam flooding simulation in models than include the reservoir heterogeneity and the real history of cyclic steam stimulation (CSS).

A. Almeida da Costa, G. Costa, and M. Embiruçu, Universidade Federal da Bahia; R. Patel, J. J. Trivedi, J.B.P. Soares, University of Alberta; J. Mateo, Computer Modelling Group; P. S. Rocha, Enauta

Abstract

Several academic and industrial researchers have studied low salinity water injection (LSWI) as a cost-effective enhanced oil recovery method. LSWI effects, however, remain unclear, particularly for clastic rocks like sandstones, which contain many clay minerals with pH-dependent surface charges. In addition, few low salinity studies exist for Brazilian sandstone rocks and light paraffinic crude oils. This case study investigates LSWI performance and mechanism experimentally and with numerical simulations using samples and data from a clastic reservoir in Recôncavo basin, northeastern Brazil. Coreflooding experiments, zeta potential and interfacial tension measurements, besides oil adsorption analysis, were performed to investigate the influence of different concentrations and pH of synthetic formation water (SFW), NaCl, and CaCl2 brine solutions on rock and oil surface charges. Ten parameters related to the injection and production of the fluids, pressure, effluent pH, oil recovery, and molality of the components were successfully matched to the coreflooding data. The experimental results and reservoir simulations indicated that when the reservoir pH changes towards alkaline conditions (driven by ionic exchanges during LSWI) the isoelectric point of pH-dependent surface charges in oil and rock minerals is approximated, weakening the electrostatic attraction between their surfaces, and consequently increasing oil recovery. A sensitivity analysis of the injection time shows that the sooner and the longer the diluted SFW cycling is applied, the greater the benefit in terms of timing and oil recovery. The optimization and sensitivity analysis indicated that the concentration of Na+ and Ca++, and the water injection rate are the most relevant parameters for designing new experiments. This study sheds light on the LSWI mechanisms for the Brazilian clastic reservoir investigated and provides useful operational parameters for designing and achieving better LSWI performance. It may assist researchers and oil companies working in similar oil reservoirs to estimate the effectiveness of using LSWI under different flooding conditions for stand-alone and hybrid LSWI applications.