This paper presents a simple yet rigorous model and provides a methodology to analyze production data from wells exhibiting three-phase flow during the boundary-dominated flow regime. Our model is particularly applicable to analyze production data from volatile oil reservoirs, and should replace the less accurate single-phase models commonly used. The methodology will be useful in rate transient analysis and production forecasting for horizontal wells with multiple fractures in shales. Our analytical model for efficiently handling multi-phase flow is an adaptation of existing single-phase models. We introduce new three-phase parameters, notably fluids properties. We also define three-phase material balance pseudotime and three-phase pseudopressure to linearize governing flow equations. This linearization makes our model applicable to wells with variable rates and flowing pressures. We optimized the saturation-pressure path and further suggested an appropriate method to calculate three-phase pseudopressures. We validated the solutions through comparisons with compositional simulation using commercial software; the excellent agreement demonstrated the accuracy and utility of the analytical solution. We concluded that, during the boundary-dominated flow regime, the saturation-pressure relation given by steady-state path and tank-type model for volatile oil reservoirs leads to satisfactory results. We also confirmed that our definitions of three-phase fluid properties are well suited for ultra-low permeability volatile oil reservoirs. The computation time of our model is greatly reduced compared to a numerical approach, and thus the methodology should be attractive to the industry. Our model is efficient and practical to be applied for production data analysis in ultra-low permeability volatile reservoirs with non-negligible water production during the boundary-dominated flow regime. This study extends existing analytical model methodology for volatile oil reservoirs and is relatively easy for reservoir engineers to understand.
Kaiyi, Zhang (Virginia Polytechnic Institute and State University) | Fengshuang, Du (Virginia Polytechnic Institute and State University) | Bahareh, Nojabaei (Virginia Polytechnic Institute and State University)
In this paper, we investigate the effect of pore size heterogeneity on multicomponent multiphase hydrocarbon fluid composition distribution and its subsequent influence on mass transfer through shale nano-pores. We use a compositional simulation model with modified flash calculation, which considers the effect of large gas-oil capillary pressure on phase behavior. We consider different average pore sizes for different segments of the computational domain and investigate the effect of the resulting heterogeneity on phase and composition distributions, and production. A two dimensional formulation is considered here for the application of matrix-fracture cross mass transfer. Note that the rock matrix can also consist of different regions with different average pore sizes. Both convection and molecular diffusion terms are included in the mass balance equations, while different reservoir fluids such as Bakken and Marcellus are considered. The simulation results show that since oil and gas phase compositions depend on the pore size, there is a concentration gradient between the two adjacent pores with different sizes. Considering that shale permeability is small, we expect the mass transfer between two sections of the reservoir/core with two distinct average pore sizes to be diffusion-dominated. This observation implies that there can be a selective matrix-fracture component mass transfer during both primary production and gas injection EOR as a result of confinement-dependent phase behavior. Therefore, molecular diffusion term should be always included in the mass transfer equations, for both primary and gas injection EOR simulation of heterogeneous shale reservoirs.
Loss of barrier assurance and primary containment occurrences whether downhole or at surface have impacted safe well operation and production funnel significantly. Complex well head design, inadequate cement behind casing, threat of shallow gas presence and multiple downhole tubulars leaks are some of the common perils in sustaining the production. Apart from frequent pressure monitoring, risk assessment and mitigation plans to tackle the issues head-on, a new fresh perspective is required to manage well integrity and diagnostic holistically. This paper will highlight application of geochemical method as the new eye to trace source of well integrity issues and emulates forensic engineering to investigate well barrier failures.
Crude and gas compositional analysis from C1 up till C36 carbon chain plays a key role in determining the possible scenarios of leak paths and type of fluid expelled from the wellbore. The best forensic analysis could be produced utilizing multiple samples which represent different stages of well life starting from open-hole exploration drilling, development, production and towards the well abandonment stage. Comparing samples composition at each stage with reference to the baseline while evaluating the existing or newly acquired cement bond and diagnostic logs will help to complete the lingering puzzle.
Results showed that the origin of the fluid samples expelled from the wellbore are successfully traced in a much more economical way with faster turn-around time compared to the conventional diagnostic method. It helps to point out the most likely well integrity elemental failure which has triggered immediate actions to revive the production. Plan to feed in the cash flow has been accelerated 6 months ahead through work-over activities and number of unhealthy well strings has been reduced by 12%. Production deferment is also reduced by half million ringgit equivalent value.
In a nutshell, the case studies provide an eye-opening insight towards predictive and quantitative well integrity solutions to support production. Forward looking the geochemical forensic method can be further tailored for strategic well diagnostic solutions as more data comes in. Time to action could be further reduced with the introduction of advanced on-site analysis technology to boost the restoration efforts.
AL-Rashidi, Hamad (Kuwait Oil Company) | AL-Azmi, Waled (Kuwait Oil Company) | AL-Azmi, Talal (Kuwait Oil Company) | Ahmed, Ashfaq (Kuwait Oil Company) | Muhsain, Batoul (Kuwait Oil Company) | Mousa, Saad (Kuwait Oil Company) | AL-Kandari, Noor (Kuwait Oil Company) | AL-Sabah, Fahad (AL-Thurya) | AL-Hajri, Mohsen (BG) | AL-Mutwa, Bandar (AAA)
Crude oil production in Um-Ghdair field is consider one of the most complex operational activities in Kuwait Oil Company due to high water cut percentage, asphaletene flocculation, high viscosity and tight emulsion phenomena. As the fluid travels through the reservoir, wellbore, flowline, all the way to the gathering center, the state of initial equilibrium is disturbed leading to change in the chemical composition of the crude oil. As pressure and temperature continue to drop, and gas escapes, more asphaltenes and heavy components may continue to flocculate all the way throughout the system until the petroleum reaches its final destination. In this pilot project, asphaltene inhibitor and viscosity reducer agents were selected for reducing oil viscosity and breaking the tight emulsion phenomena in the selected piloting well in Um-Ghdair field. It was noticed that there is an asphaltene compounds flocculate in the interface between oil and water leading to increase crude oil viscosity. The best two among 22 chemical formulations tested through the screening process at lab scale and take it to pilot stage. Additionally, the pilot study examined the influences effective for surfactants such as water composition, temperature, concentration, pH and total dissolved solids. It was noticed that the viscosity reduction and the water separation improve with increasing surfactant concentration and increasing temperature up to 50 F. Two formulations were selected based on cost effective optimal concentrations of surfactant that identified from the bottle test. The pilot has been implemented successfully in the field, resulting a reduction in non-production time and increase the oil mobility from the reservoir.
Reservoir fluid properties play a crucial role in the upstream field development cycle. Petroleum engineers extensively utilize Pressure-Volume-Temperature (PVT) studies in applications such as calculations of pipelines’ pressure drop, and assessment of Enhanced Oil Recovery (EOR) strategies. These studies are generated from a series of lab experiments conducted on reservoir fluid samples in high pressure-high temperature (HPHT) lab environments, and commonly matched using Equation of State (EOS) software.
Feeding and characterizing the composition of a reservoir fluid in a PVT software play a central role towards understanding its behavior. These steps are heavily affected by the last carbon number measured and the lumping scheme used in the simulator. This paper investigates the application of splitting the plus fraction, and utilizing Saturates, Asphaltenes, Resins and Aromatics (SARA) analysis in enhancing viscosity prediction at atmospheric conditions.
In this study, three oil samples from fields with suspected flow assurance issues were selected. A fingerprint study was first conducted on all samples to ensure that they are representative of the original reservoir fluid, and free of any drilling fluid contaminants. The methodology used in this study is based on conducting compositional analysis and viscosity test on the selected samples. Furthermore, SARA analysis was conducted to enhance the characterization of reservoir fluid, and confirm asphaltene presence. Lastly, splitting technique and SARA-based lumping scheme were used to predict viscosity values at atmospheric pressure and were compared to experimental data.
The results of this work demonstrated the effectiveness of SARA-based lumping scheme on atmospheric viscosity prediction, which captured the plus fraction concentrated in the dead oil without compromising the computational time. Furthermore, the EOS software used studied the sensitivity of the simulation results to different compositions.
Golovko, Julia (Halliburton) | Jones, Christopher (Halliburton) | Dai, Bin (Halliburton) | Pelletier, Michael (Halliburton) | Gascooke, Darren (Halliburton) | Olapade, Peter (Halliburton) | Van Zuilekom, Anthony (Halliburton)
Phase behavior characterization (PVT) and geochemical compositional analysis of petroleum samples play a crucial role in the reservoir evaluation process to help determine producible reserves and the best production strategy. Openhole samples are the most valuable types of samples for PVT and geochemical analysis. Unfortunately, traditional openhole sampling methods are costly and limited to ten to twenty samples, thereby restricting the scope of characterization in a well section. This study summarizes a new microsampling technique for logging while drilling (LWD) and a corresponding wellsite technique to provide compositional interpretation, contamination assessment, reservoir fluid compositional grading, and reservoir compartmentalization assessment. This microscale approach allows fast analysis with a field or near-field deployment of the analytical tool, providing fast turnaround time for analysis. The results inform planning for wireline sample retrieval, if necessary.
The microsampler used in the downhole tool is capable of collecting reservoir fluid in small quantities, suitable for compositional analysis. Because of its small size, the microsampler can gather multiple fluids at various reservoir depths, while PVT sampling requires larger volumes and has more constraints. However, when used in combination with conventional PVT-grade samples, the microsamples can provide significant chemical profiling. The quantity of 40 microliters (
Recovery to surface of fluid samples collected at reservoir temperature and pressure allows for analysis with an automated gas chromatograph (GC) deployed in the field, providing reduced labor and rapid analysis. The unique injection chamber of the GC is designed with the injection port and valve configured to withstand pressure up to 5,000 psi, which is approximately five times higher than standard GC injection valves. This allows for injection of the microsample with a solvent carrier as a single-phase fluid so that analysis can provide composition and fluid properties, such as gas to oil ratio, without a flash. The GC has two detectors including a flame ionization detector (FID) for hydrocarbon components and thermal conductivity detector (TCD) for inorganic gas components, such as carbon dioxide, nitrogen, and hydrogen sulfide. The system can quantify hydrocarbon components from C1-C36 and perform contamination studies of oil samples with drilling fluids.
This study provides a new technique for reservoir engineers to characterize a reservoir completely, without limit to the number of acquired samples. In combination with conventional PVT samples, it is possible to extrapolate the PVT properties to all pump-out stations, and conduct a complete geochemical profile of the reservoir.
Carlsen, Mathias Lia (Whitson AS) | Whitson, Curtis Hays (Whitson AS, NTNU) | Alavian, Ahmad (Whitson AS) | Martinsen, Sissel Øksnevad (Whitson AS) | Mydland, Stian (Whitson AS, NTNU) | Singh, Kameshwar (Whitson AS) | Younus, Bilal (Whitson AS) | Yusra, Ilina (Whitson AS)
In this paper we emphasize the duality of fluid sampling: (1)
To make a comprehensive assessment of fluid sampling in tight unconventionals, reservoir fluids ranging from black oils to gas condensates have been studied. For a wide range of fluid systems, a compositional reservoir simulator has been used to assess two main scenarios: (1) an initially undersaturated (single-phase) fluid system, and (2) initially saturated (two-phase) fluid system. To quantify how collected surface samples change with time, three properties are studied as functions of time: (1) saturation pressure and type (dewpoint | bubblepoint), (2) producing gas/oil ratio (GOR), and (3) stock-tank oil (STO) API. Observations of how these three properties change with time is used to help explain why elevated saturation pressures, greater than the initial reservoir pressure, often can be observed.
Rapid decline of the flowing bottomhole pressure (BHP | pwf), together with shut-in periods, makes it difficult to obtain in-situ representative samples in MFHW. For slightly undersaturated reservoirs, and saturated reservoirs, it may be impossible to obtain in-situ representative fluid samples because of the near-wellbore multiphase behavior. However, samples which are not in-situ representative can still be used to estimate original in-situ fluids using
Rate-transient analyses (RTA) is a useful reservoir/hydraulic fracture characterization method that can be applied to multi-fractured horizontal wells (MFHWs) producing from low permeability (tight) and shale reservoirs. In this paper, a recently-developed three-phase RTA technique is applied to the analysis of production data from a MFHW completed in a low-permeability volatile oil reservoir in the Western Canadian Sedimentary Basin.
This new RTA technique is used to analyze the transient linear flow regime for wells operated under constant flowing bottomhole pressure conditions. With the new method, the slope of the square-root-of-time plot applied to any of the producing phases can be used to directly calculate the linear flow parameter,
The subject well, a MFHW completed in 15 stages, produces oil, water and gas at a nearly constant (measured downhole) flowing bottomhole pressure. This well is completed in a low-permeability, near-critical volatile oil system. For this field case, application of the new RTA method leads to an estimate of
The new three-phase RTA technique developed herein is a simple-yet-rigorous and accurate alternative to numerical model history-matching for estimating
Development of reliable models for hydrocarbon-in-place and water saturation estimation requires knowledge about wettability of mudrocks and the parameters (including rock properties and reservoir condition) affecting it. A significant volume fraction of organic-rich mudrocks is composed of kerogen. Therefore, wettability of kerogen affects the overall wettability of organic-rich mudrocks. The chemical composition and structure of kerogen varies with kerogen type and thermal maturity, which affects the surface properties of kerogen such as wettability. In a recent publication, we demonstrated using experimental techniques that kerogen could be water-wet at low thermal maturities and oil-wet at higher thermal maturities. However, the impacts of kerogen type and reservoir temperature/pressure conditions on kerogen and mudrock wettability is yet to be quantified. Therefore, the objectives of this paper include (i) quantifying the impacts of kerogen molecular structure and composition on water adsorption capacities, (ii) quantifying the impacts of reservoir pressure and temperature on water adsorption capacity of kerogen using molecular dynamics (MD) simulations.
In order to achieve the aforementioned objectives, we use a combination of molecular dynamics simulations and experimental work. The inputs to the molecular dynamics simulations include realistic models of kerogen, which are condensed to porous kerogen structures. Water molecules are filled in kerogen pore structure and MD simulation is performed. The outputs of the simulations include radial distribution function (RDF), and adsorption isotherms of water on kerogen for different kerogen types, thermal maturities, and temperature conditions. The adsorption processes are modelled for pressure and temperature conditions ranging from 0 to 35 MPa and 320 to 370 K, respectively. The outcomes of molecular dynamics simulations demonstrated that the water adsorption capacities of kerogen vary significantly with kerogen type, thermal maturity, and temperature and pressure conditions. The RDF results showed that the water adsorption capacity decreased from type I to type III kerogen. The water adsorption capacity of kerogen was found to increase by 128% with 38% increase in oxygen content. The increase in the adsorption capacity was attributed to the strong attraction between oxygen containing functional groups in kerogen and water. The adsorption isotherms of water and kerogen samples showed that the water adsorption capacity decreased by 0.19 mmol/g as the temperature increased from 320 K to 370 K. The average water adsorption capacity of kerogen was found to increase by 20% with increase in pressure by 34 MPa. The results obtained from molecular dynamics simulations were found to be in good agreement with experimental results. The results of this paper can be used to predict the adsorption capacities of any kerogen with the availability of geochemical information. This important property of kerogen is required for estimating kerogen wettability and can enhance understanding of fluid-flow mechanisms in organic-rich mudrocks.
Cui, Xiaona (Texas A&M University and Northeast Petroleum University) | Song, Kaoping (China University of Petroleum - Beijing) | Yang, Erlong (Northeast Petroleum University) | Jin, Tianying (Texas A&M University) | Huang, Jingwei (Texas A&M University) | Killough, John (Texas A&M University) | Dong, Chi (Northeast Petroleum University)
The phase behavior shifts of hydrocarbons confined in nanopores have been extensively verified with experiments and molecular dynamics simulations. However, the impact of confinement on large-scale reservoir production is not fully understood. This work is to put forward a valid method to upscale the pore-scale fluid thermodynamic properties to the reservoir-scale and then incorporate it into our in-house compositional simulator to examine the effect of confinement on shale reservoir production.
Firstly, a pore-scale fluid phase behavior model is developed in terms of the pore type and pore size distribution (PSD) in the organic-rich shale reservoir using our modified Peng-Robinson equation of state (PR-C EOS) which is dependent on the size-ratio of fluid molecule dynamic diameter and the pore diameter. And the fluid composition distribution and PVT relation of fluids in each pore can be determined as the thermodynamic equilibria are achieved in the whole system. Results show that the initial fluid composition distribution is not uniform for different pore types and pore sizes. Due to the effect of confinement, heavier components are retained in the macropore, and lighter components are more liable to accumulate in the confined nanopores. Then an upscaled equation of state is put forward to model the fluid phase behavior at the reservoir-scale based on our modified PR-C EOS using a pore volume-weighted average method. This upscaled EOS is validated with the pore-scale fluid phase behavior simulation results and can be used for compositional simulation. Finally, two different reservoir fluids from the Eagle Ford organic-rich shale reservoir are simulated using our in-house compositional simulator to investigate the effect of confinement on production. In addition to the critical property shift which can be described by our upscaled PR-C EOS, capillary pressure is also taken into account into the compositional simulation. Results show that the capillary pressure has different effects on production in terms of the fluid type, leading to a lower producing Gas/Oil ratio (GOR) for black oil and a higher GOR for gas condensate. Critical property shift has a consistent effect on both the black oil and gas condensate, resulting in a lower GOR. It should be noted that the effect of capillary pressure on production is suppressed for both fluids with the shifted critical property.