Produced water chemical compositional data are collected from a carbonate reservoir which had been flooded by North Seawater for more than 20 years, so there is an opportunity to analyse the large amount of produced water data collected, understand the brine/brine and brine/rock interactions and explore the impact factors behind them. In some publications, core flood experimental tests were performed with chalk cores or carbonate columns in order to make an understanding of possible chemical reactions occurring triggered by injected water with different composition (Seawater, low salinity water or any other brine). However, most of the time the laboratory conditions where core flooding experiments are implemented cannot fully simulate the real reservoir conditions. Therefore, in this study, with the help of the valuable produced water dataset and some basic reservoir properties, a one-dimensional reactive transport model is developed to identify what in situ reactions were taking place in the carbonate reservoir triggered by seawater injection.
From the perspective of reservoir mineralogy, calcite, as the dominant mineral in the carbonate reservoir, is relatively more chemically reactive than quartz and feldspar which are usually found in sandstone. Whether calcite is initially and dominantly present in the carbonate reservoir rock is dissolved under seawater flooding or not is the first key issue we focused on. The effects of calcite dissolution on the sulphate scaling reactions due to incompatible brine mixing and the potential occurrence of carbonate mineral precipitation induced by calcite dissolution are investigated and discussed in detail. The comparison of simulation results from the isothermal model and the non-isothermal model show the important role of temperature during geochemical processes. The partitioning of CO2 from the hydrocarbon phase into injected brine was considered through calculation of the composition of reacted seawater equilibrated with the CO2 gas phase with fixed partial pressure (equivalent with CO2 content), then subsequently the impact of CO2 interactions on the calcite, dolomite and huntite mineral reactions are studied and explained. We also use calculation results from the model to match the observed field data to demonstrate the possibility of ion exchange occurring in the chalk reservoir.
This case study is done on a mature oil field. In this field, a thin dolomitic layer is thought to be acting as a baffle of water injector in the field. As this thin layer is less than 50 cm thick and not consistently recognizable using some conventional logs, this is a trial of using a combination of advance distance to boundary detection and ultra-high-resolution imaging tool to steer the well above this thin layer. Based on core available data, it is a dolomitized Redstone with a strong hydrocarbon stain. The tight, relative dolomite is likely to act as a baffle to vertical fluid flow. To enhance the effect of planned water injection project, placement of horizontal well just above the dolomitic layer by a meter or a meter and a half was the target for a successfully injector well in this field. Challenges to the landing of such a well includes depth, thickness, and dip uncertainties. Additionally, there are the errors that are inherent to correlating between the reservoir scale and the seismic scale. Finally, it is difficult to discern boundaries in this low-resistivity environment characterized by very low resistivity contrast. Resistivity contrast, in particular, is of major importance as it plays the main role in determining the operability of common distance-to-boundary tools.
Combination of distance to boundary detection capability and Ultra-High Resolution Imaging while drilling allowed to place wellbore precisely at certain distance from the dolomitic fluid barrier, avoid any unwanted exits and to evaluate this dolomitic layer properties by resistivity, density/neutron data known as triple-combo sideways with the above mentioned used technology for steering. The data provided were integrated with seismic surveys to refine the reservoir structure and geometry interpretation. The improved understanding made it possible to optimize recovery and production through optimum landing of the well and to map the overlying and underlying reservoir parameters.
By selecting the right tool configurations in the bottom-hole assembly (BHA), formation tops were detected from a distance of up to 2m true vertical thickness (TVT) and in the same time parallel to the dolomitic layer in most of the well trajectory. Resistivity contrast was as low as 0.3 ohm.m versus the 0.9 ohm.m when detecting the dolomitic layer marker unit. On the other hand, in some areas of the well, crossing the dolomitic layer and a one bouncing to it was needed to build the confidence in this method and confirming the steering interpretation for the future upcoming wells in the same field.
The existing literature provides little guidance on the relevance of formation damage or return permeability results obtained from reservoir-conditions core flood testing on sandstone cores with heavy formate fluids. The drilling and completion in open hole of all six production wells in the Huldra field with heavy formate fluid provided a rare opportunity to appraise the results from HPHT core flood testing carried out on Ness (North Sea Brent Group) sandstone reservoir cores as part of the original drilling fluid qualification process for the Huldra development program.
Low- and high-permeability sandstone core plugs obtained from the productive Ness reservoir formation in the Huldra field were subjected to static and dynamic exposure to heavy formate drill-in fluids under HPHT reservoir conditions at 350 psi overbalance for a period of 296 hours. The cores were then exposed to short-duration drawdowns under HPHT reservoir conditions to simulate the very early phase of production start-up. The permeability impairment results obtained in these laboratory tests were compared against the production performance data for six Huldra field wells drilled and completed with sand screens in open hole in Brent Group sandstones with the same heavy formate fluids.
The reservoir-conditions (11,400 psi, 150°C) core flooding test with a SG 1.92 formate drill-in fluid sample from a Huldra well drilling job reduced the permeability of a 1416 mD Ness core by 37.8%. The same fluid reduced the permeability of a 2.8 mD Ness core by 65.9%. Repeating the same reservoir-conditions core flooding tests with a fresh SG 1.92 formate drill-in fluid sample prepared in the laboratory gave very similar results. In all cases the permeability of the cores was restored to original levels by soaking the wellbore face of the cores at balance for 24 hours with 15% acetic acid under reservoir conditions. The full restoration of permeability by non-invasive soaking of the core faces with dilute organic acid at balance suggested that the source of the tractable impairment was residual CaCO3/polymer filter cake still pressed onto the core face after lengthy drilling fluid exposure at overbalance and a very short clean up by drawdown.
The six Huldra production wells were drilled with SG 1.92 formate fluid at 37°-54° inclinations through the Tarbert, Ness, Etive and Rannoch reservoir formations and completed in open hole with 300-micron single-wire-wrapped screens. The wells cleaned up naturally during production start-up, without the need for acid treatment, resulting in skins that were at the low end of the expected range. The Hudra field was shut down in 2014 after producing 17.3 GSm3 of gas, representing an 80% recovery of the original gas in place.
This has been a useful first appraisal of a set of historical return permeability test results obtained with heavy K/Cs formate fluids. As more data become available from other HPHT gas condensate fields developed entirely with heavy formate brines (e.g. the Kvitebjørn and Martin Linge fields) it may become possible to assign some predictive value to the results of return permeability tests with these fluids.
Abouie, Ali (The University of Texas at Asutin) | Korrani, Aboulghasem Kazemi Nia (The University of Texas at Austin) | Shirdel, Mahdy (The University of Texas at Austin) | Sepehrnoori, Kamy (The University of Texas at Austin)
Scale deposition in surface and subsurface production equipment is one of the common problems during oil production, resulting in equipment corrosion, wellbore plugging, decrease in production rate, and frequent remediations. In this work, a detailed procedure is presented through which a compositional wellbore simulator is developed with the capability of modeling comprehensive geochemical reactions.
The compositional wellbore simulator (UTWELL) is developed by applying different numerical approaches and flow-regime-detection methods to accurately model multiphase flow in the wellbore. In addition, several deposition mechanisms are incorporated for the transportation, entrainment, and deposition of solid particles in the wellbore. Subsequently, a geochemical module, IPhreeqc, is integrated into the wellbore model to handle homogeneous and heterogeneous, reversible and irreversible, and ion-exchange reactions under either local-equilibrium or kinetic conditions. This package provides a robust, flexible, and accurate integrated tool for mechanistic modeling of scale deposition in the wellbore.
Through our integrated simulator, deposition profiles of carbonate and sulfate scales in the wellbore are predicted for several case studies. Significant effects of physiochemical properties (such as pressure, temperature, salinity, and pH value) on the scale deposition in the wellbore are discussed. In addition, comparing simulation results with experimental data reveals that hydrocarbon-phase dissolution has a significant effect on geochemical calculations compared with the temperature/pressure variation effects.
To the best of our knowledge, there is no comprehensive simulator available in the industry through which scale deposition in the wellbore can be predicted accurately. In this paper, scale deposition profile in the wellbore is estimated by including the interaction of the hydrocarbon and aqueous phases and its effect on the aqueous-scale geochemistry (by use of a compositional wellbore simulator); effects of parameters that vary greatly in the wellbore (pressure, temperature, and pH value); and comprehensive geochemistry simulation (provided through coupling of the wellbore simulator with IPhreeqc). The outcome of this study yields a comprehensive tool for scale deposition prediction in the wellbore and will help scale deposition risk-management and mitigation plans.
Nitrate has been used to control Sulphate Reducing Bacteria (SRB) in oil and gas reservoirs. Nitrate is thermodynamically a strong oxidizer, which could increase carbon steel corrosion rates yet; literature documenting the effect of nitrate on corrosion is scarce and contradictory.
This study investigated the effect of nitrate on carbon steel corrosion under simulated oilfield produced water (rich in carbon dioxide with pH~5) and simulated seawater (minimum carbon dioxide and a pH~7). CO2 corrosion tests were conducted with carbon steel X65 exposed to uninhibited brines at 25°C, 60°C, and 80°C via rotating cylinder electrode (RCE). Inhibited synthetic brine was tested under acidic environments at 80°C. Changes in nitrate, nitrite, ammonium and ferrous ions were monitored using ion chromatography.
The results provide experimental evidence to demonstrate that the corrosivity of nitrate strongly depends on pH. Nitrate tends to increase CO2 corrosion rates in the presence of synthetic produced brine (pH~5) and is relatively benign when added to synthetic seawater (pH~7). At the conditions tested, nitrite impurities contained within the source of nitrate tend to increase carbon steel corrosion exposed to synthetic brines.
In the presence of metallic iron and under CO2 environments, nitrate reduces to ammonium, which is thermodynamically stable in acid solutions. The reduction of nitrate can be modelled based on first order kinetics. The main factors promoting the reduction of nitrate are pH, iron to nitrate ratio, and temperature.
Scale deposition in surface and subsurface production equipment is one of the common problems during oil production resulting in equipment corrosion, wellbore plugging, decrease in production rate, and frequent remediations. In this work, we present a detailed procedure through which a compositional wellbore simulator is developed with the capability of modeling comprehensive geochemical reactions.
The compositional wellbore simulator (UTWELL) is developed by applying different numerical approaches and flow regimes to accurately monitor multiphase flow in the wellbore. In addition, several deposition mechanisms are incorporated and validated against experimental data to study the transportation, entrainment, and deposition of solid particles in the wellbore. Subsequently, a geochemical module (i.e. IPhreeqc) is integrated into the wellbore model to handle homogenous and heterogeneous, reversible and irreversible, and ion-exchange reactions under either local equilibrium or kinetic conditions. This package provides a robust, flexible, and accurate integrated tool for mechanistic modeling of scale deposition in the wellbore.
Through our integrated simulator, deposition profiles of carbonates and sulfates scales in the wellbore are predicted for several realistic case studies. Significant effects of physiochemical properties (i.e. pressure, temperature, salinity, and
To the best of our knowledge, there is no comprehensive simulator available in the industry through which scale deposition in the wellbore can be predicted accurately. In this work, by including 1) the interaction of the hydrocarbon phases on the aqueous-scale geochemistry (by using a compositional wellbore simulator) 2) effects of parameters that vary greatly in the wellbore (i.e. pressure, temperature, and
Disproportionate permeability reduction (DPR) may provide field solutions to address high volumes of water production and efficiency of oil recovery in non-communicating layered reservoirs. This work evaluates the lab-scale DPR effectiveness at different formation wettability conditions using an environmentally friendly, water-soluble, silicate gelant. A robust, time/temperature stable and easy-to-design water-soluble silicate gelant system is utilized to conduct DPR treatments in oil- and water-wet cores using a newly established steady-state, two-phase chemical system placement. The experimental procedure is applied to ensure the presence of moveable oil saturation at which the injected DPR fluid (gelant) gels in the treated zone and to quantitatively control the placement saturation conditions in the formation. DPR treatments are conducted using a steady-state, two-phase (oil/gelant) placement to better control the water/oil saturation at which the silicate gel sets. The performance of water-soluble, silicate-based DPR treatments are evaluated using pre- and post-treatment two-phase (brine/oil) steady-state and unsteady state permeability measurements.
Strongly water-wet Berea cores are chemically treated to alter their wettability to oil wet and measured phase effective permeability curves are used to characterize the newly established core wettability. Treatment design should include filterability/injectivity and rheological studies of the DPR fluid to evaluate gelant interaction with the formation as well as gelation time and kinetics. Single-phase DPR fluid injectivity through Berea cores is excellent. At relatively high watercuts in water-wet cores, two-phase DPR-fluid/oil injectivity is good and even better in oil-wet cores regardless the watrecut. At relatively low watercuts in water-wet cores, the injectivity is not as good as in higher watercuts and the mobility reduction keeps increasing with the co-injection of the DPR-fluid/oil.
DPR-fluid/oil placement experiments conducted at the same saturation conditions and water/oil ratio (WOR) showed that the ultimate oil residual resistance factor in oil-wet cores is significantly lower than the one in water-wet cores. This is mainly due to more favorable oil-phase continuity and distribution in oil-wet media compared to the corresponding ones in water-wet formations. In water-wet cores, encapsulation of oil by gel may cause oil-phase discontinuities and porous medium conductivity reduction. Wettability tests have shown that silicate gel is strongly water-wet. Therefore, in oil-wet DPR treatments, formed gel in porous media yields a mixed-wet formation and a lower trapped oil saturation compared to the water-wet formation.
In either wetting state, relative permeability hysteresis was insignificant during the post-DPR treatment imbibition/drainage cycles. This also reflects stable gels during post-DPR treatment floods. DPR treatments conducted at high WOR in oil-wet cores have shown a minor gel "erosion" during the post-treatment two- and single-phase (water) injection; gel "erosion" ceased during oil injection. DPR treatments conducted at high WOR caused an increase in residual resistance factor (
Inflow Control Valve (ICV) have been used in the past to enhance performance of producing wells for unfavorable environments, such as non-uniform permeability and pressure variation along the well sections. Nowadays, since Enhanced Oil Recovery (EOR) technique has been advanced, the ICV is introduced to be installed in the injector well, with the aim to produce more oil from the reservoir. The key factor in the success of this project was the use of Petrel to simulate the injection sweep across the entire Alpha reservoir section. Nozzle type ICV is used to obtain a piston-like water injection profile, and thus to achieve the objective of increasing sweep efficiency to recover more oil, and decrease water breakthrough in high permeability zone, if connected to the producers. Firstly, the reservoir is analyzed to choose the best candidate of injection well. Then, the sector modeling is run at the region near the injection well. The sector modeling reduces the time required to run the ICV simulation study. After that, the Base Case is created with open hole injection well. The result of the run is recorded. Then, ICV is installed with the sensitivity studies on the different valve apertures. The results show that the installation of ICV improves the oil recovery by 2%. The optimal depletion strategy for major oil reservoir is pressure maintenance by water injection with ICV. The full field simulation shows that the water production is reduced by 20% for the full field. Therefore, it shows that intelligent completion concepts can be applied at injection well besides at production well. This paper presents an innovative completion technology, fine tuned by reservoir simulations, for balancing the water injection profile into various sand formations zones in an open-hole completed injector well, increasing sweep efficiency.|
Recently the problem of associated petroleum gas utilization in Russian gas and oil production fields has attracted a lot of attention. According to the Russian Government the new strict utilization requirements as well as high flaring penalties will be applied to the oil producing companies starting from 2014. At the same time, increasing water cut during the well production life is another problem facing the oil and gas operation. Thus, optimal multiphase oil/water/gas flow separation will become vital for Russia for successful oil development and exploitation in the near future.
Inline separation technology can be the new solution to solve the mentioned challenges. Inline separation is the compact separation in swirl pipe segments. In comparison to the conventional vessel-type separation, the inline technology is simple, low-cost, low-weight, has no moving parts, needs low maintenance, easy to install and operate. These features fit the exigent conditions expected in hostile production environments, and suitable to both new fields and retrofit applications.
This paper describes the inline separation technology, including an overview of qualification work and field experiences. The fundamental mechanisms behind these techniques are explained, and recent advances in these methods are emphasized. The paper especially addresses a test program developed for Marlim production site for reservoir support and gives an excellent example how inline technology can be used to make step-change improvements to the gas, oil, and water management.
Today the global oil industry is increasingly challenged to carry out complex and capital intensive oil and gas developments whilst ensuring that the recovery of the hydrocarbons over the field life is maximized and that safety and environmental demands are met. Oil and gas separation at the oil well is one of the core operations before transport, sale and refinery. Currently, processing becomes increasingly complex while the quality of produced hydrocarbons keeps deteriorating. Changes of water cut and reservoir pressure during field life; switch from primary oil to gas production; developing new fields in extreme environment (arctic, ultra-deep offshore, etc.) and as a result new requirements on equipment - all of that had a great impact on development new methods and approaches in separation technology. Optimal solutions for multiphase oil/water/gas flow separation are vital for further successful oil and gas development and exploitation.
A technological breakthrough within the application of wireline technologyhas been achieved. In August 2008 on an offshore platform on the Norwegiancontinental shelf, a wireline tractor and a new wireline milling system wereused to mill and remove a permanent bridge plug at 4,147 ft measured depth(MD).
The operator decided to mill out the plug on electric wireline and workedclosely with the service company to develop this novel solution. Havingdeveloped and tested several bits and milling tools, results showed that bycombining the wireline miller with hydraulically provided weight on bit (WOB),it would be possible to mill out the retaining rings of the plug, which wouldcause the plug to collapse. The milling-control unit allows the WOB to beadjusted for each application and also controls the reactive torque--the forcegenerated when the milling bit engages the plug.
The service company was able to develop the solution within the client'sparameters and in accordance with the timeline set out for this project. Theoffshore operation was completed in 3 days, to the operator's satisfaction.
In another platform well, a permanent bridge plug had been set in 2003 inthe sealbore between two screen sections [3-ft sealbore, 67° well angle,4.75-in. inner diameter (ID)]. The plug was set in order to isolate thesomewhat higher water cut in the lower reservoir zone to prolong oil productionfrom the well. In 2006, the well drowned after a 2-week-maintenance period. Twoyears later, a coiled-tubing (CT) gas lift operation was carried out with goodresults. It was then decided to remove the permanent bridge plug to reopen forproduction before another CT gas lift operation was carried out. A method formilling the permanent bridge plug was developed on the basis of lessons learnedfrom the other plug-milling operation and by extensive testing at the servicecompany's facilities. The operation was completed successfully in 13 days.
This new application for milling completion hardware and other wellboreobstructions offers a cost-efficient alternative to existing methods. Thesuccess of the milling operation is a significant achievement and has pushedthe limits for what is possible on electric wireline.
This paper will examine two cases of milling bridge plugs on electricwireline and the technical challenges that had to be overcome in offshoreoperations.The first case used the well stroker as WOB, and the second casedused the well tractor as WOB.