Asphaltene Deposition Research Articles

TECHNOLOGICAL COMPLICATIONS (FORMATION DAMAGE) DURING CO2 INJECTION FOR ENHANCED OIL RECOVERY. PART 3. PREVENTING AND REPAIRING FORMATION DAMAGE CAUSED BY CO2 INJECTION

The article considers technological complications arising during CO2 injection for enhanced oil recovery, with a focus on the formation of asphaltenes in the pore space and their negative impact on production efficiency. Formation of asphaltene solids in the reservoir leads to an increase in the skin factor, their removal to the wells, accumulation in the wellbore and on the surface of the equipment, which reduces oil flow to the well and requires expensive remedial work. Methods of identification and monitoring of asphaltene deposits are considered. Results of laboratory studies confirming the difficulty of quantitative assessment of asphaltene deposition are given, as well as practical examples of application of various technologies for their prevention and removal. Methods including the use of inhibitors and dispersants and the use of aromatic solvents to restore reservoir properties are reviewed. It also emphasises the need for continuous monitoring of field operations and the development of effective asphaltene management methods, which is critical to improving the economic feasibility of CO2 injection projects.

Simultaneous use of disulphide oil for chemical‐enhanced oil recovery by emulsion formation and stability with asphaltene deposition control

AbstractDisulphide oil (DSO) is a by‐product of oil and gas refining processes that is generated during the removal of mercaptans and the sweetening of light hydrocarbons. Asphalt deposition, especially asphaltene deposition during enhanced oil recovery methods, reduces oil recovery from the reservoir, so the use of a substance such as DSO, which has the ability to control and reduce asphaltene deposition, can be effective in increasing oil recovery from the reservoir. In this research, a micromodel with a fracture design and a matrix that represents fracture reservoirs was utilized. These tests were conducted in two groups. The first group of tests is related to adding DSO to crude oil and using 70 to 30 vol.% oil–water emulsion containing salt, surfactant, and nanoparticles. The second group involved adding DSO to both crude oil and emulsion. The first group aimed at stimulation and the second group aimed at chemical enhanced oil recovery (C‐EOR). The formation and stability of water‐in‐oil emulsion was done by analyzing the average droplet size. As a result, in the first group of tests with the presence of DSO in the oil, by measuring the average diameter before and after injection of AOS surfactant, it was observed that the average droplet size decreased from 6.89 to 4.01 μm, which indicates an increase in the emulsion stability. In the second group, where DSO was present in both oil and water emulsion in injected oil, it can be seen that the average diameter of the droplets in the surfactant decreased from 5.12 to 3.21 μm.

Data Science Enables Management of Stealth Asphaltene Flow-Assurance Risk

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 216216, “Managing Stealth Asphaltene Flow-Assurance Potential Risk in Gas-Injection Field Based on Data Science Using Over 20-Year Accumulated Data Set,” by Hideharu Yonebayashi, SPE, and Takeshi Hiraiwa, SPE, Japan Oil Development, and Khuloud T. Al Khlaifi, SPE, ADNOC, et al. The paper has not been peer reviewed. _ Gas injection is recognized generally not only to improve oil recovery but also to increase the risk of asphaltene destabilization. The recent discovery of asphaltene deposits in a subject field motivated the operator to launch an immediate investigation to evaluate what critical risks might exist and consider appropriate mitigation. It was found that precipitated but invisible asphaltenes still can be flowable. This stealth asphaltene behavior could explain a possible mechanism of the first asphaltene observation in the upper reservoir. Introduction The subject giant offshore field in the Arabian Gulf has not experienced asphaltene-induced production deterioration during long-term lean hydrocarbon gas injection. The gas has been injected into the crestal area of two reservoirs (upper and lower) with peripheral powered seawater injection. Both reservoir fluids contain a small amount of asphaltenes (0.1–1.5 wt%) distributed at higher concentration at deeper locations. In May 2022, the first discovery of asphaltene deposits from the historical no-issued area in the upper reservoir motivated an immediate investigation for risk assessment and mitigation. A resulting study captured stealth asphaltenes, which were detected by a laser-light-scattering technique while high-pressure microscopy detected no visible asphaltene solid particles. Historical Asphaltene Data Accumulation The permeability range and pore-throat size of the subject field are relatively low in the lower reservoir compared with the upper. Both reservoirs are under highly unstable asphaltene-stability conditions. The reservoir pressure-maintenance scheme, consisting of dump-floodwater injection followed by peripheral powered seawater injection and crestal gas injection, however, has maintained asphaltene-free production except for the gas-injection pilot (GIP) during 2005–2009. No asphaltenes have been observed in the crestal gas-injection area; however, asphaltene deposits were observed in the GIP area in 2007. The injected gas was enriched gradually by a vaporizing gas-drive process. The previous studies involving numerical modeling analysis and laboratory experiments reported that enriched hydrocarbon gas can more easily allow asphaltene precipitation compared with lean hydrocarbon gas. GIP Asphaltene Risk Analysis (Upper Reservoir). In 2009, an asphaltene flow-assurance risk evaluation was conducted using the single-phase bottomhole sample collected from Well 6, which is 90 ft shallower that the GIP area and far from the crestal gas-injection area. Therefore, the Well 6 reservoir fluid was not affected by injection gas. The bottomhole condition of the GIP production well was entered into the asphaltene precipitation envelope (APE) that was expanded by injection-gas enrichment but never covered by the APE without an enrichment process. Latest Laboratory Analysis (Lower Reservoir). In 2022, an asphaltene flow-assurance risk evaluation was conducted. After the location was narrowed to a depth range, Well 1 was selected by taking an asphaltene gradient into account.

Innovative xanthan gum-based nanocomposites for asphaltene precipitation prevention in shale and carbonate rocks

Asphaltene deposition in porous media creates many challenges in porous media. This study synthesizes ZnO/SiO2/xanthan nanocomposites (NCs) to adsorb asphaltene and reduce its effect on the shale and carbonate rocks. NCs structure is analyzed using SEM, EDX, BET, and FTIR tests. Also, the rocks' surface is analyzed by an atomic force microscopy (AFM) test after 48 and 96 h of contact with 20 ppm NCs and 20 mg asphaltene. Core flooding tests are performed on shale rocks using 20 ppm NCs at 5500, 4000, and 2500 psi at 48 h. Using AFM in calcite and dolomite formations and selecting core flooding tests based on that are new scenarios that followed in this paper. FTIR results confirm asphaltene adsorption on NCs's surface by changing 854 and 962 cm−1 peaks. AFM tests confirmed asphaltene adsorption on NCs surface, too. Average roughness, root mean square roughness, peak to valley roughness, and average size of the shale were higher than the carbonate sheets. At 20 ppm NCs in shale reservoirs, permeability reduction in porous media was increased up to 39.5 %, and asphaltene precipitation decreased from 8.95 and 20.06 wt% to 2.25 and 10.25 wt%, which shows our suggested scenarios were efficient.

Synthesis of novel green nanocomposites by considering enhanced oil recovery and asphaltene adsorption effectiveness in calcite and dolomite formations

Asphaltene deposition is known as the main issues in reservoirs, which causes formation damage in reservoir. This research investigated the effects of a newly introduced green nanocomposites, namely eucalyptus/CuO/Fe3O4/xanthan nanocomposites (EC-NCs), on the inhibition of asphaltene precipitation in calcite and dolomite formations. First, at two time steps of 48 and 96 h, asphaltene adsorption on EC-NCs surfaces was examined through scanning electron microscope (SEM) tests in both calcite and formation tests. Moreover, asphaltene adsorption on the surface of EC-NCs was confirmed through isotherm models including Langmuir and Freundlich and the interfacial tension between CO2 and oil. Finally, a series of static and dynamic tests were performed at the highest adsorption pressure points, including 4200, 3950, and 3700 psi, and at the highest adsorption time step, i.e., 96 h, and the effects of asphaltene adsorption were seen on permeability reduction and asphaltene precipitation. EC-NCs exhibited superior efficacy in both asphaltene adsorption and precipitation inhibition. Two separate pressure changes were observed, and the ratios of the interfacial tension slope in the 2nd to the 1st regions [1st: 200–2700 psi, 2nd:2700–4200 psi] were changed from 19.44 % to 25.00 % and 29.74 % in 48 and 96 h, respectively, and this confirms that asphaltene had indeed adhered to the surface of the EC-NCs. Moreover, at 48, and 96 h, the size reductions of particles in SEM for calcite and dolomite were (29.27 %, 56.81 %), and (59.09 %, 62.25 %), respectively, which shows asphaltene adsorption was more efficient in dolomite formation, and in 96 h.

Fractionation and Characterization of Acidic Compounds of Flowline and Separator Asphaltene Deposits from a Gulf of Mexico Field

Fractionation and Characterization of Acidic Compounds of Flowline and Separator Asphaltene Deposits from a Gulf of Mexico Field

Application of MgO based‐nanofluid for controlling the growth of asphaltene flocs under static and micromodel dynamic conditions

AbstractIn this study, the impact of magnesium oxide (MgO) nanoparticles on the control of asphaltene aggregates growth was examined. The investigation began with static testing, followed by dynamic testing, where nanofluid was injected into a constructed glass micromodel simulating a porous medium. The results obtained from light microscopy and asphaltene dispersant tests demonstrated that the MgO nanoparticles with an average diameter of 50 nm postpone the asphaltene onset point (AOP) and delay the growth of asphaltene aggregates in crude oil. Also, the results obtained from these experiments illustrated the performance of synthesized nanoparticles in various concentrations on inhibition of asphaltene deposit in the crude oil medium, in the order of 750 > 1500 > 100 > 1000 > 500 ppm. The results from both microscopy and ADT experiments strongly validate the effectiveness of MgO nanoparticles across varying concentrations, highlighting the optimal dosage of 750 ppm. Images of nanofluid flooding at the optimal concentration in the glass micromodel demonstrate effective nanoparticle inhibition and enhanced oil recovery from the porous medium. These findings corroborate the results obtained from ADT and microscopy tests. The results of FT‐IR analysis show the adsorption of asphaltene particles on the surfaces of MgO nanoparticles in wavelengths of 2900–3000 cm−1. Moreover, dynamic light scattering (DLS) analysis results indicated that the average diameter of suspended particles was 3580 nm before adsorption and 6230 nm after adsorption, indicating the controlled adsorption of asphaltene onto the surface of MgO nanoparticles. The findings from this study can be applied to manage asphaltene formation across all stages of oil processing and production.

Asphaltene deposition effects on reservoir rock wettability and modification strategies

Asphaltene deposition, a widespread challenge in the petroleum industry, detrimentally affects oil production, transport, and processing. Our study investigates asphaltene's impact on sandstone and carbonate reservoir rock wettability using ASTM-D6560 extraction and heptol solutions. A significant part of our focus was to examine wettability change due to asphaltene damage and the use of nanoparticles to improve this situation. Qualitatively, advanced techniques reveal altered rock composition, and contact angle measurements, along with zeta potential assessments, highlight significant wettability changes. Quantitatively, asphaltene-infused solutions induce a quantifiable increase in contact angles. Specifically, with gamma alumina nanoparticle addition, contact angles rise from 68° to 87° for sandstone and 110°–142° for carbonate rocks. Temperature variations within our experimental range also induce notable wettability changes. These findings establish a clear link between asphaltene deposition and quantifiable wettability modifications, providing crucial insights for optimizing oil recovery processes and enhancing well performance in the petroleum industry. The study's results suggest that nano-gamma alumina can be an effective solution for improving wettability and mitigating asphaltene deposition issues in carbonate rocks, offering promising prospects for the oil and gas industry.

Numerical model of asphaltene deposition in vertical wellbores: Considerations of particle shape and drag force

Asphaltene deposition and plugging are common phenomena during crude oil production, significantly reducing production efficiency. Understanding the deposition behavior of asphaltene particles in vertical wellbores, particularly in relation to drag force interactions and settlement velocity, is imperative to mitigate these issues. Existing empirical models often fail due to their inherent inaccuracies and neglect of asphaltene particles' irregular shapes. This work established a quantitative method to describe irregular geometries of asphaltene particles. Shape coefficient, ∅, and shape coefficient influence factor, θ, are used to assess the impact of particle shape on the drag force coefficient and settling velocity. Experimental results from sedimentation experiments reveal particles with smaller shape coefficients encounter greater flow resistance and higher drag force coefficients. Moreover, the impact of shape coefficient on the drag coefficient gradually decreases as the Reynolds number increases. Based on these experimental findings, distinct models for the drag force coefficient and settling velocity of asphaltene particles are established, achieving a reduction in average error ranging between 2 % ∼ 25 % compared to existing models.

TECHNOLOGICAL COMPLICATIONS (FORMATION DAMAGE) DURING CO2 INJECTION FOR ENHANCED OIL RECOVERY. Part 2. INTERACTION OF CO2 WITH FORMATION OIL: WETTABILITY CHANGE, ASPHALTENE PRECIPITATION AND DEPOSITION IN THE FORMATION

In the second part of the review (the first part was published in [1]) the processes of formation damage at CO2 injection due to the oil phase stability disturbance are considered. Changes in reservoir temperature, pressure or fluid composition due to CO2 dissolution can provoke asphaltene precipitation and deposition. Their adsorption on the reservoir pore surface leads to a change in decrease in rock permeability. The currently ac wettability and a cepted numerical models describe well the experimental results on colmatation of pore media by asphaltenes in the presence of CO2, with different equations for asphaltene adsorption and kinetics of their occurrence being used in the models. Asphaltenes precipitated in pore volumes migrate with formation fluids to production wells and can form deposits that complicate oil production.

Modifying the Effects around the Well can have an Impact on the Drilling Process

Environmental changes around a well can significantly affect the drilling process. This paper examines the effects of flow rate, bottomhole pressure, sheet permeability, viscosity, pressure gradient and well radius on the drilling process. It is shown that the energy-dynamic instability of the sheet’s near-shiva space, a highly active region in the formation, leads to changes in reservoir rock and fluid properties during the drilling process. These changes include physicochemical transformations such as deposition of asphaltenes, paraffins, and resins, as well as swelling of clay particles, which can disrupt reservoir physical properties and affect hydrocarbon flow. In addition, completion and production techniques and the chemistry of drilling and pressure fluids are particularly critical for low-permeability reservoirs. In this paper, the concept of skin effect is also introduced to assess the impact of process fluids on the bottomhole region, and a new assessment model is proposed. The results of the study are important for improving drilling technology and optimising reservoir development.

Enhanced oil recovery in tight reservoirs by ultrasonic-assisted CO2 flooding: Experimental study and molecular dynamics simulation

CO2-enhanced oil recovery (CO2-EOR) has attracted great attention due to its dual effects of geological carbon storage and economic benefits, but the clay swelling, asphaltene deposition and gas channeling induced by CO2 still restrict its field application. The employment of chemical agents for the purpose of improving CO2-EOR performance is often limited by the heterogeneity of reservoirs and the potential for formation damage. Physical methods, such as ultrasonic-assisted CO2 flooding, appear to offer a promising alternative for CO2-EOR and geological sequestration. This study has conducted oil displacement experiments to investigate the EOR potential of ultrasonic-assisted CO2 flooding in tight reservoirs and clarify the effects of different ultrasound parameters. The ultrasonic waves with 20 kHz of acoustic frequency, 30 W/cm2 of sound intensity, 30 min of sonication time and moderate intermittent working mode can yield violent cavitation effects and avoid undesirable energy dissipation. Nearly a quarter of the saturated crude oil can be recovered from the tight core through ultrasonic-assisted CO2 flooding. It can be attributed to the composition alterations of crude oil and property changes of core matrix. Coupling with ultrasonic waves, CO2 would extract and vaporize crude oil more easily, which promotes oil swelling, lowers oil density and viscosity, decreases oil–gas interfacial tension and thus improves oil recovery. Besides, the ultrasound can help to mitigate the impact of CO2 adsorption-induced clay swelling on pore sizes through fluctuating pressure. And the strong hydrodynamic shear forces generated by mechanical vibration of ultrasound may also help to connect individual small pores and extend micro-fractures. These synergistic effects result in the transformation of micropores into mesopores and macropores. Furthermore, the wettability alteration of core samples implies that the ultrasonic-assisted CO2 flooding can induce the detachment of oil films from the rock surface. Finally, the results of molecular dynamics simulations indicate that the improvement in pressure inside the core sample resulting from ultrasonic cavitation facilitates the mixing of CO2 and oil, thereby weakening gas channeling and improving the displacement efficiency.

Evaluation of heavy hydrocarbon liquid in the Eastern Dahomey Basin, Southwestern Nigeria (case study of Agbabu Bitumen in Ondo State)

Solvent-aided dilution processes are often employed to recover bitumen by reducing its viscosity. In this study, methanol, toluene, and xylene were investigated as potential hydrocarbon solvents for solvent-aided hydrocarbon recovery of Agbabu bitumen. To achieve this, the solubility of the sample in the solvents was determined with a solubility test, its viscosity was measured with the Saybolt Furol Viscometer using the ASTM D88 method, and its SARA analysis was conducted using high-performance liquid chromatography. Agbabu bitumen was found to have a high content of saturates and aromatics. Viscosity decreases as pressure increases, while solubility reduces as temperature increases. The sample was most soluble in toluene, and its viscosity was reduced most in it, followed by xylene. Methanol reduced the saturates content and significantly raised the asphaltene content, keeping the mixture viscosity high. In terms of asphaltene stability of the mixtures, the bitumen-methanol system with the lowest colloidal instability index of 0.874 will give a mild asphaltene deposit issues compared with others that are unstable. This approach of combining multiple tests with the CII can accurately predict the behavior of Agbabu bitumen in solvents and enhance decision on the choice of bitumen recovery technology.

Impact of various aggregation kinetics on thermophoretic velocity of asphaltene deposition.

Asphaltene deposition may pose serious challenges to flow assurance of crude oil in well columns. Different aggregation kinetics would partly be responsible for asphaltene particle growth ending in deposition on the surface of well columns. This work primarily investigates the thermophoretic deposition velocity caused by temperature gradients inside well columns for various asphaltene aggregation kinetics, including crossover behaviour, sedimentation, reaction-limited aggregation (RLA), and diffusion-limited aggregation (DLA). To do so, the experimental observations of size distribution for a live crude oil was performed at 80°C and pressure range of 4500-5500 psia. Moreover, various patterns of different size distributions were gathered from the literature for the sake of comparison. Next, a well column in southern Iran was selected to study the kinetic behaviour of thermophoretic velocity of deposition, with a difference between geothermal and static temperatures of around 5 to 50°C. The non-isothermal deposition velocity was shown to decrease from the top to the bottom of the well column, according to the findings of the study. The results also revealed that the thermophoretic velocity decreases as particle size increases and vice versa. This was confirmed by examining a comparably large range of asphaltene particle sizes, ranging from approximately 100 nm to roughly 9 µm. Practical implications of these findings were also discussed which would provide guidance for mitigation of asphaltene deposition in well columns.

Extended Review and Experimental Setup Development for Continuous Solvent and Oil Coinjection for Asphaltene Deposition in Porous Media

Extended Review and Experimental Setup Development for Continuous Solvent and Oil Coinjection for Asphaltene Deposition in Porous Media

Mitigating Asphaltene Deposition in CO2 Flooding with Carbon Quantum Dots

Carbon capture, utilization, and storage (CCUS) technology has emerged as a pivotal measure in mitigating global climate change. Notably, CO2-EOR is esteemed for its dual function of sequestering CO2 and enhancing oil recovery. However, this process presents challenges related to asphaltene deposition during CO2 flooding, leading to reservoir damage, such as pore plugging. This study systematically manipulated the factors inducing CO2-induced asphaltene deposition, elucidating the mechanisms and magnitudes of asphaltene precipitation. Additionally, the study investigated the efficacy of carbon quantum dots (CQDs) in mitigating asphaltene deposition. Experimental findings indicated a positive correlation between asphaltene deposition and level of asphaltene content, CO2 injection ratio, and temperature. Moreover, with an increase in experimental pressure, the asphaltene deposition rate demonstrated an initial increase followed by a subsequent decline. Leveraging their favorable compatibility with asphaltene, CQDs effectively suppressed the aggregation behavior of asphaltene. In the presence of CQDs, the onset of asphaltene precipitation was delayed from 45 V% to 55 V%, with the highest inhibition rate reaching approximately 36% at an optimal CQD concentration of 20 mg/L. This study proposes a novel approach to address asphaltene deposition issues in CO2-EOR processes, contributing to the enhancement of recovery rates in low-permeability reservoirs.

Investigation of Asphaltene Precipitation and Reservoir Damage during CO2 Flooding in High-Pressure, High-Temperature Sandstone Oil Reservoirs

Summary Asphaltenes are heavy aromatic hydrocarbon compounds contained in reservoir fluids and may precipitate when the reservoir pressure is reduced by production or when gas is injected into the reservoir, and then further deposit on pore-throat surfaces causing reservoir damage. At present, the research on asphaltene precipitation and reservoir damage is carried out in conventional reservoirs, and the influence of CO2 injection under high-pressure, high-temperature (HPHT) conditions has not yet been clearly understood. In this work, we combined perturbed-chain statistical association fluid theory (PC-SAFT) calculation, experiments, phase-state simulation, and numerical simulation to predict the asphaltene precipitation with different pressures, temperatures, and amounts of injected gas and to clarify the influence on reservoir permeability and oil production when using CO2 injection. The results show that the precipitation of asphaltenes in the process of CO2 injection is the desorption of colloid-asphaltene inclusions caused by gas molecules and then the mutual polymerization process between dispersed asphaltene molecules. CO2 injection will increase the amount of precipitation and move the precipitation curve to the right side. The degree of permeability reduction caused by the deposition of asphaltenes in the core is 12.87–37.54%; the deposition of asphaltenes in the reservoir is mainly around the injection/production wells and along the injected gas profile. Considering asphaltenes, the oil recovery degree is reduced by 1.5%, and the injection rate is reduced by 17%. The reservoir pressure, temperature, and physical properties have a strong correlation with the degree of reservoir damage, while the initial asphaltene content has a low correlation. This work will be of great interest to operators seeking to enhance oil recovery by CO2 injection in deep reservoirs.

Investigating Asphaltene Precipitation and Deposition in Ultra-Low Permeability Reservoirs during CO2-Enhanced Oil Recovery

CO2 flooding is an economically feasible and preferred carbon capture, storage, and utilization technology. Asphaltene deposition is a common problem in the process of CO2 injection because it may cause reservoir damage. The mechanism of asphaltene precipitation damage to the formation remains elusive. Experiments were conducted to reveal the pore-scale formation damage mechanism in ultra-low permeability reservoirs caused by asphaltene precipitation during CO2 flooding. Initially, the precipitation onset point for asphaltene within the crude oil-CO2 system was determined using a high-pressure tank equipped with visual capabilities. Subsequently, CO2 flooding experiments were conducted on ultra-low permeability cores under miscible and immiscible conditions, with the support of nuclear magnetic resonance (NMR) to quantitatively evaluate the impact of asphaltene precipitation on ultra-low permeability reservoirs. The results indicate that within the pressure range from the asphaltene precipitation onset point to the minimum miscibility pressure (MMP). The level of asphaltene precipitation rises as CO2 injection pressure increases. In the miscible flooding stage, asphaltene precipitation can still occur, but to a lesser extent. Notably, asphaltene deposition predominantly occurs in larger pores; above the MMP, the permeability decreases significantly as asphalt particles agglomerate, resulting in notable pore-throat blockages. While asphaltene deposition has a minimal impact on porosity, the bridging effect of asphaltene particles reduces permeability.

The characteristics of produced oils in the miscible CO2 displacement process

CO2 flooding is an effective technique for enhancing oil recovery by changing the hydrocarbon fluid’s characteristics. One of the fundamental mechanisms of the interaction between CO2 and hydrocarbon fluid by miscible CO2 injection is the extraction phenomenon of the hydrocarbon components by CO2. It results in altered produced and residual oil characteristics. This study aims to examine the characterizations of produced oil during the process of CO2 displacement. It is critical to anticipate any issues that can arise from miscible CO2 flooding, such as asphaltene deposition. A light-dead oil sample from an Indonesian oil field was used in this investigation. The miscible CO2 displacement process was conducted by a slim tube experiment at operating temperature of 90°C and 70°C, which represents the reservoir and surface temperature, respectively. The properties of produced oil were further characterized by analyzing the composition based on its polarity, including saturate, aromatic, resin, and asphaltene. The results show that increasing injection pressures decrease resin and asphaltene fractions in produced oil. Furthermore, the proportions of asphaltene and resin fractions in the crude sample exhibit a significant decrease when conducted at a lower temperature in comparison to when carried out at a higher temperature. This study helps to explain how the displacement process by CO2 affects the properties of the produced oil.

Mathematical Model of Asphaltene Deposition During Oil Production

Mathematical Model of Asphaltene Deposition During Oil Production