Characterizing Pores and Pore-Scale Flow Properties in Middle Bakken Cores

SPE Journal ◽  
2018 ◽  
Vol 23 (04) ◽  
pp. 1343-1358 ◽  
Author(s):  
Somayeh Karimi ◽  
Hossein Kazemi
Keyword(s):  
Capillary Pressure ◽  
Oil Recovery ◽  
Oil And Gas ◽  
Produced Water ◽  
Nitrogen Adsorption ◽  
Spontaneous Imbibition ◽  
Flow Properties ◽  
Resistivity Measurements ◽  
Fluid Saturation ◽  
Shale Reservoirs

Summary To understand the flow and transport mechanisms in shale reservoirs, we needed reliable core-measured data that were not available to us. Thus, in 2014, we conducted a series of diverse experiments to characterize pores and determine the flow properties of 12 Middle Bakken cores that served as representatives for unconventional low-permeability reservoirs. The experiments included centrifuge, mercury-intrusion capillary pressure (MICP), nitrogen adsorption, nuclear magnetic resonance (NMR), and resistivity. From the centrifuge measurements, we determined the mobile-fluid-saturation range for water displacing oil and gas displacing oil in addition to irreducible fluid saturations. From MICP and nitrogen adsorption, we determined pore-size distribution (PSD). Finally, from resistivity measurements, we determined tortuosity. In addition to flow characterization, these data provided key parameters that shed light on the mechanisms involved in primary production and the enhanced-oil-recovery (EOR) technique. The cores were in three conditions: clean, preserved, and uncleaned. The hydrocarbon included Bakken dead oil and decane, and the brine included Bakken produced water and synthetic brine. After saturating the cores with brine or oil, a set of drainage and imbibition experiments was performed. NMR measurements were conducted before and after each saturation/desaturation step. After cleaning, PSD was determined for four cores using MICP and nitrogen-adsorption tests. Finally, resistivity was measured for five of the brine-saturated cores. The most significant results include the following: Centrifuge capillary pressure in Bakken cores was on the order of hundreds of psi, both in positive and negative range. Mobile-oil-saturation range for water displacing oil was very narrow [approximately 12% pore volume (PV)] and much wider (approximately 40% PV) for gas displacing oil. In Bakken cores, oil production by spontaneous imbibition of high-salinity brine was small unless low-salinity brine was used for spontaneous imbibition. Resistivity measurements yielded unexpectedly large tortuosity values (12 to 19), indicating that molecules and bulk fluids have great difficulty to travel from one point to another in shale reservoirs.

In-Situ Phase Pressures and Fluid Saturation Dynamics Measured in Waterfloods at Various Wettability Conditions

2010 ◽  
Vol 13 (03) ◽  
pp. 465-472 ◽  
Author(s):  
Amund Brautaset ◽  
Geir Ersland ◽  
Arne Graue
Keyword(s):  
Capillary Pressure ◽  
Oil Recovery ◽  
Spontaneous Imbibition ◽  
Flow In Porous Media ◽  
Relative Permeabilities ◽  
Dynamic Capillary Pressure ◽  
Fluid Saturation ◽  
Local Recovery ◽  
Capillary Pressure Curves

Summary During waterfloods of six outcrop chalk core-plug samples prepared at various wettabilities, simultaneous local pressures and in-situ fluid saturations were measured. Using high-spatial-resolution magnetic-resonance imaging (MRI) to image fluid saturations and pressure taps with semipermeable disks to measure individual phase pressures allowed calculations of relative permeabilities and the dynamic capillary pressure curves for the imbibition processes. A second objective was to identify individual-fluid saturation changes caused by spontaneous imbibition and viscous displacement to determine the local recovery mechanism and to calculate local recovery factors and in-situ Amott-Harvey indices. The obtained results contribute to improved description and understanding of multiphase-fluid flow in porous media, including in situ measurements of relative permeabilities, dynamic capillary pressure curves, Amott-Harvey Indices, and local oil-recovery mechanisms.

An Experimental Research on Enhanced Oil Recovery Using Local Polymers

2021 ◽  
Author(s):  
Abiola Oyatobo ◽  
Amalachukwu Muoghalu ◽  
Chinaza Ikeokwu ◽  
Wilson Ekpotu
Keyword(s):  
Enhanced Oil Recovery ◽  
Experimental Research ◽  
Oil Recovery ◽  
Capital Investment ◽  
Oil And Gas ◽  
Produced Water ◽  
Water Injection ◽  
Gum Arabic ◽  
Oil And Gas Industry ◽  
Profile Control

Abstract Ineffective methods of increasing oil recovery have been one of the challenges, whose solutions are constantly sought after in the oil and gas industry as the number of under-produced reservoirs increases daily. Water injection is the most extended technology to increase oil recovery, although excessive water production can pose huge damage ranging from the loss of the well to an increase in cost and capital investment requirement of surface facilities to handle the produced water. To mitigate these challenges and encourage the utilization of local contents, locally produced polymers were used in polymer flooding as an Enhanced Oil Recovery approach to increase the viscosity of the injected fluids for better profile control and reduce cost when compared with foreign polymers as floppan. Hence this experimental research was geared towards increasing the efficiency of oil displacement in sandstone reservoirs using locally sourced polymers in Nigeria and also compared the various polymers for optimum efficiency. Starch, Ewedu, and Gum Arabic were used in flooding an already obtained core samples and comparative analysis of this shows that starch yielded the highest recovery due to higher viscosity value as compared to Ewedu with the lowest mobility ratio to Gum Arabic. Finally, the concentration of Starch or Gum Arabic should be increased for optimum recovery.

scholarly journals Innovative Optical-Sensing Technology for the Online Fouling Characterization of Silicon Carbide Membranes during the Treatment of Oily Water

Sensors ◽  
2020 ◽  
Vol 20 (4) ◽  
pp. 1161
Author(s):  
Mehrdad Ebrahimi ◽  
Axel A. Schmidt ◽  
Cagatay Kaplan ◽  
Oliver Schmitz ◽  
Peter Czermak
Keyword(s):  
Silicon Carbide ◽  
Oil Recovery ◽  
Oil And Gas ◽  
Produced Water ◽  
Cross Flow ◽  
Oil And Gas Industry ◽  
Ceramic Membranes ◽  
Transmembrane Pressure ◽  
Sensing Technology ◽  
Water Sensor

The oil and gas industry generates a large volume of contaminated water (produced water) which must be processed to recover oil before discharge. Here, we evaluated the performance and fouling behavior of commercial ceramic silicon carbide membranes in the treatment of oily wastewaters. In this context, microfiltration and ultrafiltration ceramic membranes were used for the separation of oil during the treatment of tank dewatering produced water and oily model solutions, respectively. We also tested a new online oil-in-water sensor (OMD-32) based on the principle of light scattering for the continuous measurement of oil concentrations in order to optimize the main filtration process parameters that determine membrane performance: the transmembrane pressure and cross-flow velocity. Using the OMD-32 sensor, the oil content of the feed, concentrate and permeate streams was measured continuously and fell within the range 0.0–200 parts per million (ppm) with a resolution of 1.0 ppm. The ceramic membranes achieved an oil-recovery efficiency of up to 98% with less than 1.0 ppm residual oil in the permeate stream, meeting environmental regulations for discharge in most areas.

scholarly journals ANALISIS PENGOLAHAN AIR TERPRODUKSI DI WATER TREATING PLANT PERUSAHAAN EKSPLOITASI MINYAK BUMI (STUDI KASUS: PT XYZ)

2015 ◽  
Vol 12 (2) ◽  
pp. 78
Author(s):  
Pertiwi Andarani ◽  
Arya Rezagama
Keyword(s):  
Oil Recovery ◽  
Oil And Gas ◽  
High Efficiency ◽  
Produced Water ◽  
Enhanced Recovery ◽  
Good Condition ◽  
Gas Production ◽  
Energy Company ◽  
Steam Flooding ◽  
Water Handling

The exploration and production process of oil and its supporting operations always generates wasteas by-product. If they are uncontrolled, it might decrease the environmental quality. Thus, it isnecessary to manage and treat the waste in order to meet the regulation standard of quality andquantity. PT XYZ is an energy company, particularly oil and gas production, which its productionactivity generate a large amount of waste as well as produced water. Thus, PT XYZ must havefacilities or produced water handling plant which could minimize pollution caused by produced water.PT XYZ already has a system of produced water handling with recycling principle. After oil and waterseparation including water treating at Water Treating Plant (WTP), produced water will be used forsteam injection. This is the part of enhanced oil recovery by steam flooding in Duri Field. Besides,produced water could be used as backwash water at WTP, that is Oil Removal Filter (ORF) and WaterSoftener, which is called brine water. If the produced water and brine water is over load the capacity ofoil enhanced recovery injection, it might be disposed through injection to Disposal Well and there arecertain condition that produced water should be discharged into canal. The objective f this study is toanalyze the performance of a water treating plant in PT XYZ. Water Treating Plant is a facility fortreating produced water. Basically, WTP is on good condition and each unit has high efficiency forseparating oil and water (60-99%). Horizontal velocity at pit #A of API Separator was larger than thedesign criteria. In addition, Water Softeners have efficiency until 99% for the hardness.

Geochemical Monitoring of Formation Fluids for Reservoir Management Considering Complicating Factors in Mature Oilfields

2021 ◽  
Author(s):  
Mariya Sergeevna Shipaeva ◽  
Danis Karlovich Nurgaliev ◽  
Artem Aleksandrivich Zaikin ◽  
Vladislav Anatolevich Sudakov ◽  
Artur Albertovich Shakirov ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Oil And Gas ◽  
New Technologies ◽  
Produced Water ◽  
Point Of View ◽  
Geochemical Monitoring ◽  
Digital Revolution ◽  
Stage Of Development ◽  
Modern Development ◽  
Geochemical Studies

Abstract At the present stage of the hydrocarbon production process, most of the unique and largest fields in the world are at a late stage of development. Despite the active development and policy of a decarbonised economy, the demand for liquid and gaseous hydrocarbons remains high, while of inevitably growing the number of mature fields. The Volga-Ural oil and gas province today is an old oil and gas producing region, most of the fields have already entered the final stage of development. However, through the introduction and development of new technologies for oil extraction, monitoring of production and localization of reserves, the life of the fields can be extended. One of these technologies is geochemical monitoring of well production. Its goal is to optimize the development of mature fields on the basis of promptly obtained information about the state of the wells using geochemical studies of the formation fluid, allowing timely implementation of the necessary measures. Geochemical studies allow identifying the source of fluid entering the well, determining a violation in the wellbore structure, checking the tightness of downhole equipment for separate operation, and performing an area analysis of the area development efficiency. This type of research is relevant both in giant fields with a large stock of production wells, often characterized from a geological point of view by multilayer structure, with technological complexity, packing, wear of equipment and strings, in some cases the impossibility of running gauge for research, and in fields with low depletion. The possibilities of geochemistry for solving local operational problems in wells are shown. Several hydrogeological complexes have been studied, the change in the properties of the produced water during the development process is described. The concepts of the geochemical conditions in the hydrocarbon deposits that existed earlier are changing due to the development of these objects as a dynamic system, continuous injection of different types of water into the reservoir, the use of enhanced oil recovery methods and other technogenic impact associated with the development of reserves. The digital revolution and the modern development of the industry marked the beginning of the creation of the Digital Atlas of Groundwater, the development of specialized algorithms that allow processing large amounts of data.

Curbing the Climate Footprints of Oil and Gas

2021 ◽  
pp. 95-116
Author(s):  
Deborah Gordon
Keyword(s):  
Oil Recovery ◽  
Carbon Capture ◽  
Oil And Gas ◽  
Produced Water ◽  
Ghg Emissions ◽  
Climate Index ◽  
Supply Side ◽  
Demand Side ◽  
Renewable Electricity ◽  
Mitigation Potential

Chapter 4 lays out real-world solutions from the Oil Climate Index + Gas (OCI+). It argues that demand-side strategies, while necessary, have not been sufficient. An array of supply-side oil and gas strategies are needed to curb global warming. Numerous strategies that mitigate upstream, midstream, and downstream greenhouse gas (GHG) emissions are enumerated, including (1) eliminating routine flaring, (2) using renewable electricity, (3) using only manmade carbon dioxide for enhanced oil recovery, (4) reusing and pumping produced water more efficiently, (5) employing green hydrogen in refining, (6) locking up carbon in noncombustible end uses, (7) sequestering heavy residuals for reclamation and reuse, (8) reducing GHG emissions from liquefied natural gas, (9) decommissioning legacy assets with high GHGs, (10) minimizing fossil fuel inputs, (11) employing leak-free equipment, (12) operating permanent carbon capture, and (13) avoiding operating in sensitive ecosystems. The chapter concludes by presenting the cumulative mitigation potential of supply-side oil and gas strategies that are the responsibility of various actors.

Will Carbon Dioxide Injection in Shale Reservoirs Produce from the Shale Matrix, Natural Fractures, or Hydraulic Fractures?

2021 ◽  
Author(s):  
Sherif Fakher ◽  
Youssef Elgahawy ◽  
Hesham Abdelaal ◽  
Abdulmohsin Imqam
Keyword(s):  
Carbon Dioxide ◽  
Oil Recovery ◽  
Oil And Gas ◽  
Fractured Reservoirs ◽  
Co2 Injection ◽  
Hydraulic Fractures ◽  
Natural Fractures ◽  
Recovery Potential ◽  
Shale Reservoirs ◽  
The Impact

Abstract Enhanced oil recovery (EOR) in shale reservoirs has been recently shown to increase oil recovery significantly from this unconventional oil and gas source. One of the most studied EOR methods in shale reservoirs is gas injection, with a focus on carbon Dioxide (CO2) mainly due to the ability to both enhance oil recovery and store the CO2 in the formation. Even though several shale plays have reported an increase in oil recovery using CO2 injection, in some cases this method failed severely. This research attempts to investigate the ability of the CO2 to mobilize crude oil from the three most prominent features in the shale reservoirs, including shale matrix, natural fractures, and hydraulically induced fracture. Shale cores with dimensions of 1 inch in diameter and approximately 1.5 inch in length were used in all experiments. The impact of CO2 soaking time and soaking pressure on the oil recovery were studied. The cores were analyzed to understand how and where the CO2 flowed inside the cores and which prominent feature resulted in the increase in oil recovery. Also, a pre-fractured core was used to run an experiment in order to understand the oil recovery potential from fractured reservoirs. Results showed that oil recovery occurred from the shale matrix, stimulation of natural fractures by the CO2, and from the hydraulic fractures with a large volume coming from the stimulated natural fractures. By understanding where the CO2 will most likely be most productive, proper design of the CO2 EOR in shale can be done in order to maximize recovery and avoid complications during injection and production which may lead to severe operational problems.

Experimental and Numerical Assessment of Chemical Enhanced Oil Recovery in Oil-Wet Naturally Fractured Reservoirs

SPE Journal ◽  
2016 ◽  
Vol 21 (03) ◽  
pp. 0706-0719 ◽  
Author(s):  
Bernard Bourbiaux ◽  
André Fourno ◽  
Quang-Long Nguyen ◽  
Françoise Norrant ◽  
Michel Robin ◽  
...  
Keyword(s):  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Scale Effects ◽  
Fractured Reservoirs ◽  
Spontaneous Imbibition ◽  
Cocurrent Flow ◽  
Chemical Additives ◽  
Fluid Saturation ◽  
Aqueous Solvent ◽  
Chemical Eor

Summary Among various ways to extend the lifetime of mature fields, chemical enhanced-oil-recovery (EOR) processes have been subject of renewed interest in the recent years. Oil-wet fractured reservoirs represent a real challenge for chemical EOR because the matrix medium does not spontaneously imbibe the aqueous solvent of chemical additives. The present paper deals with chemical EOR by use of wettability modifiers (WMs). The kinetics of spontaneous imbibition of chemical solutions in oil-wet limestone plugs and mini-plugs was quantified thanks to X-ray computed-tomography (CT) scanning and nuclear-magnetic-resonance (NMR) measurements. Despite the small size of samples and the slowness of experiments, accurate recovery curves were inferred from in-situ fluid-saturation measurements. Scale effects were found quite consistent between mini-plugs and plugs. During a second experimental step, viscous drive conditions were imposed between the end faces of a plug, to account for the possibly significant contribution of fracture viscous drive to matrix oil recovery. The recovery kinetics and behavior, especially the occurrence of countercurrent and cocurrent flow, are interpreted through the analysis of modified forces in the presence of a diffusing or convected WM that alters rock wettability and reduces water/oil interfacial tension (IFT) to a lesser extent. This work calls for an extensive modeling study to specify the conditions on chemical additives and recovery-process implementation that optimize the recovery kinetics.

scholarly journals Current Challenges and Advancements on the Management of Water Retreatment in Different Production Operations of Shale Reservoirs

Water ◽  
2021 ◽  
Vol 13 (15) ◽  
pp. 2131
Author(s):  
Rahmad Syah ◽  
Alireza Heidary ◽  
Hossein Rajabi ◽  
Marischa Elveny ◽  
Ali Akbar Shayesteh ◽  
...  
Keyword(s):  
Fresh Water ◽  
Oil Recovery ◽  
Produced Water ◽  
Water Volume ◽  
Treatment Procedure ◽  
Industrial Plants ◽  
Offshore Production ◽  
Stage Separation ◽  
Flotation Method ◽  
Shale Reservoirs

Nowadays, water savings on industrial plants have become a significant concern for various plants and sections. It is vitally essential to propose applicable and efficient techniques to retreat produced water from onshore and offshore production units. This paper aimed to implement the PFF (Photo Fenton Flotation) method to optimize the water treatment procedure, as it is a two-stage separation technique. The measurements were recorded for the HF (hydraulic fracturing) and CEOR (chemically enhanced oil recovery) methods separately to compare the results appropriately. To assure the efficiency of this method, we first recorded the measurements for five sequential days. As a result, the total volume of 2372.5 MM m3/year of water can be saved in the HF process during the PFF treatment procedure, and only 20% of this required fresh water should be provided from other resources. On the other hand, the total volume of 7482.5 MM m3/year of water can be saved in CEOR processes during the PFF treatment procedure, and only 38% of this required fresh water should be provided from other resources. Therefore, the total water volume of 9855 MM m3 can be saved each year, indicating the efficiency of this method in supplying and saving the water volume during the production operations from oilfield units.

Experimental Investigation of Two-Phase Flow Properties of Heterogeneous Rocks for Advanced Formation Evaluation

2021 ◽  
Author(s):  
Pierre Aérens ◽  
Carlos Hassan Torres-Verdin ◽  
D. Nicolas Espinoza
Keyword(s):  
Capillary Pressure ◽  
Relative Permeability ◽  
Two Phase Flow ◽  
Time Lapse ◽  
Phase Flow ◽  
Flow Properties ◽  
Fractional Flow ◽  
Two Phase ◽  
Fluid Saturation ◽  
Heterogeneous Rocks

Abstract An uncommon facet of Formation Evaluation is the assessment of flow-related in situ properties of rocks. Most of the models used to describe two-phase flow properties of porous rocks assume homogeneous and/or isotropic media, which is hardly the case with actual reservoir rocks, regardless of scale; carbonates and grain-laminated sandstones are but two common examples of this situation. The degree of spatial complexity of rocks and its effect on the mobility of hydrocarbons are of paramount importance for the description of multiphase fluid flow in most contemporary reservoirs. There is thus a need for experimental and numerical methods that integrate all salient details about fluid-fluid and rock-fluid interactions. Such hybrid, laboratory-simulation projects are necessary to develop realistic models of fractional flow, i.e., saturation-dependent capillary pressure and relative permeability. We document a new high-resolution visualization technique that provides experimental insight to quantify fluid saturation patterns in heterogeneous rocks and allows for the evaluation of effective two-phase flow properties. The experimental apparatus consists of an X-ray microfocus scanner and an automated syringe pump. Rather than using traditional cylindrical cores, thin rectangular rock samples are examined, their thickness being one order of magnitude smaller than the remaining two dimensions. During the experiment, the core is scanned quasi-continuously while the fluids are being injected, allowing for time-lapse visualization of the flood front. Numerical simulations are then conducted to match the experimental data and quantify effective saturation-dependent relative permeability and capillary pressure. Experimental results indicate that flow patterns and in situ saturations are highly dependent on the nature of the heterogeneity and bedding-plane orientation during both imbibition and drainage cycles. In homogeneous rocks, fluid displacement is piston-like, as predicted by the Buckley-Leverett theory of fractional flow. Assessment of capillary pressure and relative permeability is performed by examining the time-lapse water saturation profiles. In spatially complex rocks, high-resolution time-lapse images reveal preferential flow paths along high permeability sections and a lowered sweep efficiency. Our experimental procedure emphasizes that capillary pressure and transmissibility differences play an important role in fluid-saturation distribution and sweep efficiency at late times. The method is fast and reliable to assess mixing laws for fluid-transport properties of rocks in spatially complex formations.

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