A New Laboratory Technique to Enhance Proppant Consolidation During Propped Hydraulic Fracturing Treatment

The objectives of this investigation were to perform a rock mechanical study to evaluate long term stability of Resin-Coated Proppant (RCP), combined with various additives currently being used in screenless propped hydraulic fracturing completions in the sandstone formations. Thereby providing a tool for the industry to know exactly the duration of the shut-in time before putting a well back onto production. A new experimental method was developed to monitor the curing process of RCP as temperature increases. The velocity of both shear and compressional waves were being monitored as a function of temperature, while the tested RCP sample was being housed in a pressurized vessel. The pressurized vessel was subjected to a variable temperature profile to mimic the recovery of the reservoir temperature following a propped hydraulic fracturing treatment. The placed proppant should attain an optimum consolidation to minimize the potential for proppant flow back. The study has been performed on various types of RCP samples under a range of reservoir conditions. The role of closure stress, temperature, curing time and carrier fluids in attaining a maximum strength of RCP following a propped hydraulic fracturing treatment have been investigated. Also, the Unconfined Compressive Strength (UCS) of various types of RCP have been measured. The testing methods currently practiced in the industry to qualify proppant for field applications are based on physical characterization of several parameters such as the specific gravity of proppant, absolute volume, solubility, roundness, sphericity and bulk density. The sieve analysis, compressive strength, and API crush testing are also measured and reported. The API Recommended Practices; API RP56, API RP58 and API RP60 are the main procedures used to test the suitability of proppants for hydraulic fracturing treatment. However, there is no published API testing method for RCP; therefore this study introduces a new testing procedure, using acoustic velocity as a function of temperature and compressive strength as a function of time; to qualify a given RCP for a particular reservoir of known stress and temperature. The final outcome of this study is to establish a functional procedure for such measurements, in order to maximize the success of a propped hydraulic fracturing treatment and minimize the occurrence of flow back incidents.

Application of in-plastic catalysis for extraction of hard-to-recover hydrocarbons

The object of research is the catalytic effect (hydrocracking) for the production of hard-to-recover hydrocarbons, the subject of the study is the change in the physicochemical properties of hydrocarbons by partial gasification, and the lightening of the fractional composition of hydrocarbons. One of the most problematic areas is the lack of studies of the catalytic effect on hard-to-recover hydrocarbons in reservoir conditions. Although processes such as catalytic cracking, reforming, isomerization, aromatization and alkylation of hydrocarbons are known and used in petroleum refining. The research used the methods of scientific knowledge – experiment and measurement. In the course of laboratory work, an effective catalyst was developed, the effect of temperature on the fractional composition and physicochemical properties of oil, oil products and gas condensate was investigated. To simulate formation conditions, hermetic metal retorts were used, in which oil and gas condensate samples were subjected to different temperature regimes. In the process of testing cores saturated with gas condensate, the dependence of filtration on physical parameters – temperature and pressure, fractional composition, specific gravity and viscosity was studied. Laboratory studies have shown a decrease in density and viscosity of hydrocarbons, an increase in core permeability. The effect of catalysis on oil made it possible to increase the volume of light ends distillation from 30 to 60 %, for gas condensate – up to 50 %, which confirms the effectiveness of the method of catalysis of hard-to-recover hydrocarbons. This is due to the fact that the correct formulation and solution of the problem provided adequate results. In contrast to the existing processes of hydrocracking of petroleum products, the proposed method allows you to extract heavy and low-mobile hydrocarbons in reservoir conditions at lower temperatures of 120–150 °С. At the same time, the technology for catalytic hydrogenation of hard-to-recover hydrocarbons will be similar to a typical treatment of a formation with an acid or surfactants. This will make it possible to intensify the commercial reserves of hydrocarbons in the fields that are now classified as hard-to-recover and which account for more than 50 %.

Identification of Micro Fractures in Cretaceous Bioclastic Limestone in Iraq and Its Influence on Development of Reservoirs

It is generally believed that Cretaceous bioclastic limestone in Mesopotamia basin in central and southern Iraq is a typical porous reservoir with weak fracture development. Therefore, previous studies on the fracture of this kind of reservoir are rare. As a common seepage channel in carbonate rock, fracture has an important influence on single well productivity and waterflooding development of carbonate reservoir. Based on seismic, core and production data, this study analyzes the development characteristics of fractures from various aspects, and discusses the influence of fractures on water injection development of reservoirs. Through special processing of seismic data, it is found that there are a lot of micro fractures in Cretaceous bioclastic limestone reservoir. Most of these micro fractures are filled fractures without conductivity under the original reservoir conditions. However, with the further development of the reservoir, the reservoir pressure, oil-water movement, water injection and other conditions have changed, resulting in the original reservoir conditions of micro fractures with conductivity. The water cut of many production wells in the high part of reservoir rises sharply. In order to describe the three-dimensional spatial distribution of fractures, the core data is used to verify the seismic fracture distribution data volume. After the verification effect is satisfied, the three-dimensional fracture data volume is transformed into the geological model to establish the permeability field including fracture characteristics. The results of numerical simulation show that water mainly flows into the reservoir through high angle micro fractures. Fractures are identified by seismic and fracture model is established to effectively recognize the influence of micro fractures on water injection development in reservoir development process, which provides important guidance for oilfield development of Cretaceous bioclastic limestone reservoir in the central and southern Iraq fields.

Capturing the Dynamics of Foam Coarsening in a HPHT Microfluidic System

The foam coarsening process is significant to foam stability in porous media. This study provides, for the first time, direct visualization of the foam coarsening process in porous media under realistic reservoir conditions. Foam coarsening behavior in porous media has shown a similar linear increase in the average bubble area to that in an open system but differs in two stages. The average bubble area increases with a faster rate in stage 1 and then increases with a slower rate in stage 2 and stage 2 dominates the foam coarsening process. The transition between the two stages occurs as the inner bubbles disappear when the edge bubbles start feeling the effects of the walls. The foam at steady-state shows a bimodal size distribution with bubbles trapped in the pore bodies and pore throats. The effects of pore pressure (600-3200 psi) and temperature (22-100 °C) were studied. Foam coarsening dynamics are sensitive to pore pressure and temperature, where higher pore pressure and lower temperature are more favorable to maintain a stable foam. Finally, the coarsening rates of foams generated with different gas phases were compared. In contrast to N2 foam and gas CO2 foam, supercritical CO2 foam exhibits the slowest coarsening rate because of its ultralow interfacial tension.

Accurate Live Interfacial Tension for Improved Reservoir Engineering Practices

Current reservoir simulators use interfacial tension (IFT) values derived from dead oil measurements at ambient conditions or predicted from literature correlations. IFT is highly dependent on temperature, pressure and fluid composition. Therefore, knowledge of the IFT value at reservoir conditions is essential for accurate reservoir fluid characterization. This study compares IFT values from dead and live oil measurements and the results of literature predicted values, thereby clearly showing the weakness of existing correlations when trying to predict crude oil IFT. A total of ten live oils was sampled for this study. Using the pendent drop technique, IFT was measured for each oil at different conditions: in the under-saturated region at reservoir pressure and temperature, in the saturated region at reservoir temperature, and for dead oil at ambient conditions. Basic PVT properties such as gas to oil ratio (GOR), gas and liquid composition, density, viscosity and molecular weight were also measured. The bubble point for each oil was identified to define the pressure step in the saturated region for extra IFT measurement. The equilibrium IFT values for the live oils were generally higher than for the corresponding dead oils. For oils where this general trend was not observed, contaminations were found in the crude samples. The use of current literature correlations does not allow to predict correct reservoir IFT. Therefore, this study provides accurate live IFT values for a variety of reservoir fluids and conditions in combination with live oil properties, highly beneficial to reservoir engineers, allowing better oil production planning.

Ciecze robocze – ich właściwości technologiczne i rola w procesie rekonstrukcji odwiertów

A workover fluid is a type of special liquids used at the end of borehole drilling, i.e. during well operation or during reconstruction works. Such works, carried out at various stages of borehole operation, are aimed at maintaining or increasing the production of a specific well and at maintaining its proper technical condition. They may be carried out only after injecting the workover fluid into the borehole, which should generate counterpressure on the reservoir, preventing the inflow of reservoir media into the borehole, and should enable the maintaining of the hydraulic conductivity of the reservoir rock. To ensure that the basic requirements are satisfied by the workover fluid injected into the borehole, its physical and chemical properties must correspond to the geological and reservoir conditions of the specified level of reservoir rocks. Due to this, the composition of the workover fluid should be determined based on the reservoir pressure gradient, mineralogical composition of reservoir rocks and of their binder, as well as the chemical composition of reservoir waters. These are the basic criteria for selection of the composition and evaluation of the quality of the workover fluid, which enable control of the physicochemical processes occurring within the borehole zone, such as clogging of the porous space of rocks, hydration of clay minerals, capillary effects and changes in the surface tension at the interface, as well as the interaction of fluid with reservoir waters. Limitation of the intensity of occurrence of such processes, which affect the degree of damage to the permeability of the reservoir rocks in horizons featuring normal or reduced reservoir pressure, largely depends on the type of workover fluid used, i.e. brine without a solid phase and brine containing a solid phase or a liquid with density below 1.0 kg/dm3. The composition and technological properties of the workover fluid, properly selected to the specific geological and reservoir conditions, allow one to maintain the productivity of the well to a degree that does not require application of additional treatment, such as acid-treatment, fracturing and reperforations. The aim of the monograph is to show the role of a workover fluid in the conducted reconstruction treatments, as well as the importance of its technological properties in limiting damage to the permeability of reservoir rocks within the borehole zone. The presented issues comprise: • causes and threats to the deterioration of reservoir rock permeability resulting from the application of an improperly selected workover fluid; • tasks of the workover fluid and methods to improve its technological properties in terms of protecting the hydraulic conductivity of reservoir rocks; • types of workover fluids developed, the methodology for determination and assessment of their technological properties, as well as usability under reservoir conditions. The monograph also includes a short description of other special liquids used in the preparation of a well for exploitation. These are: washing and cleaning liquids, packer fluids and those used for perforation, as well as buffers for rope operations and pipe cleaning prior to packer fluid injection. The presented issue is a synthesis of a wide range of research and development works carried out at the INiG - PIB. It has been prepared based on the obtained results of laboratory tests carried out for geological and reservoir conditions existing in the productive horizons of the Carpathian Foredeep, as well as of the Carpathians and the Polish Lowlands. Keywords: borehole reconstruction, geological and reservoir conditions, workover fluid tasks, workover fluid properties, chemicals, blockers, permeability

Machine Learning Predictive Models to Estimate the Minimum Miscibility Pressure of CO2-Oil System

One of the most critical parameters of the CO2 injection (for EOR purposes) is the Minimum Miscibility Pressure MMP. The determination of this parameter is crucial for the success of the operation. Different experimental, analytical, and statistical technics are used to predict the MMP. Nevertheless, experimental technics are costly and tedious, while correlations are used for specific reservoir conditions. Based on that, the purpose of this paper is to build machine learning models aiming to predict the MMP efficiently and in broad-based reservoir conditions. Two ML models are proposed for both pure CO2 and non-pure CO2 injection. An important amount of data collected from literature is used in this work. The ANN and SVR-GA models have shown enhanced performance comparing to existing correlations in literature for both the pure and non-pure models, with a coefficient of R2 0.98, 0.93 and 0.96, 0.93 respectively, which confirms that the proposed models are reliable and ready to use.

Injectivity and Propagation of Sulfonated Acrylamide-Based Copolymers in Low Permeability Carbonate Reservoir Cores in Harsh Salinity and Temperature Conditions : Challenges and Learnings from a Middle East Onshore Case Study

Polymer flooding is one of the most mature EOR technology applied successfully in a broad range of reservoir conditions. The last developments made in polymer chemistries allowed pushing the boundaries of applicability towards higher temperature and salinity carbonate reservoirs. Specifically designed sulfonated acrylamide-based copolymers (SPAM) have been proven to be stable for more than one year at 120°C and are the best candidates to comply with Middle East carbonate reservoir conditions. Numerous studies have shown good injectivity and propagation properties of SPAM in carbonate cores with permeabilities ranging from 70 to 150 mD in presence of oil. This study aims at providing new insights on the propagation of SPAM in carbonate reservoir cores having permeabilities ranging between 10 and 40 mD. Polymer screening was performed in the conditions of ADNOC onshore carbonate reservoir using a 260 g/L TDS synthetic formation brine together with oil and core material from the reservoir. All the experiments were performed at residual oil saturation (Sor). The experimental approach aimed at reproducing the transport of the polymer entering the reservoir from the sand face up to a certain depth. Three reservoir coreflood experiments were performed in series at increasing temperatures and decreasing rates to mimic the progression of the polymer in the reservoir with a radial velocity profile. A polymer solution at 2000 ppm was injected in the first core at 100 mL/h and 40°C. Effluents were collected and injected in the second core at 20 mL/h and 70°C. Effluents were collected again and injected in the third core at 4 mL/h and 120°C. A further innovative approach using reservoir minicores (6 mm length disks) was also implemented to screen the impact of different parameters such as Sor, molecular weight and prefiltration step on the injectivity of the polymer solutions. According to minicores data, shearing of the polymer should help to ensure good propagation and avoid pressure build-up at the core inlet. This result was confirmed through an injection in a larger core at Sor and at 120°C. When comparing the injection of sheared and unsheared polymer at the same concentration, core inlet impairment was suppressed with the sheared polymer and the same range of mobility reduction (Rm) was achieved in the internal section of the core although viscosity was lower for the sheared polymer. Such result indicates that shearing is an efficient way to improve injectivity while maximizing the mobility reduction by suppressing the loss of product by filtration/retention at the core inlet. This paper gives new insights concerning SPAM rheology in low permeability carbonate cores. Additionally, it provides an innovative and easier approach for screening polymer solutions to anticipate their propagation in more advanced coreflooding experiments.