This paper applies Peak Over Threshold (POT) model of extreme value theory, using Generalized Pareto Distribution (GPD) which can give more accurate description on long-heavy-tailed distribution of crude oil prices dynamics. The baseline data are long-run series of historical daily spot prices (WTI and Brent) and basket prices (OPEC). Since the focus is risk perspective of oil producers, this study exercises the loss value of crude oil prices, negative difference of a particular day with previous one.
Value at Risk (VaR) is empirically quantified based on on historical trends, volatility and correlation to estimate the likelihood that given losses will exceed a certain amount. The threshold are determined by
The focus is to apply modern method of risk assessment, providing an alternative tool / methodology of quantitative risk analysis for company E&P projects, especially during dynamic-oil-price environment.
Mega-extended-reach wells (MERWs) can be drilled from one platform to develop the remote surrounding satellite oil & gas reservoirs in deepwater. Though the platform is located in shallow water, some MERWs can be targeted the reservoirs in deepwater. In mega-extended-reach drilling (MERD) to deepwater target, some challenges that may be faced are the presence of low temperature, typically weak overburden sediments, unconsolidated formations and a small sedimentary coverage above the reservoir. This results in a narrow safe mud weight window (SMWW) and a limited well depth for MERD operation. In this work, considering the pressure balance of bottom hole including the thermal and seepage effects, a method for predicting the maximum allowable well depth (MAMD) of MERD to deepwater target is presented. Meanwhile the factors affecting the MAMD of MERD to deepwater target are also investigated. The study shows that seepage significantly affects the MAMD of MERD to deepwater target while the thermal's effect is not very obvious, seepage turns out to significantly decrease the MAMD whereas heating the formation is found to be helpful in extending the MAMD. It also shows that the predicted MAMD of MERD turns out to be obvious anisotropy, drilling in the direction of minimum horizontal in-situ stress in the formation is prone to attain a wider SMWW and a longer MAMD than other directions. Moreover, for a given target zone, the MERD with a horizontal bottom hole has a much longer MAMD than that of MERD with an inclined bottom hole, and the MAMD can also be effectively increased by reducing the annular pressure loss. This work provides a practical tool for enhancing the design of MERWs to develop the remote satellite oil & gas reservoirs in deepwater.
This paper is expected to be a lesson Learns of using nitrate-based fluid as an alternative solution to improve drilling performance and production optimization old wells.
This Lesson Learns begins from literature studied, laboratory test, field trials and continuous improvements.
Nitrate Completion Fluids have good solubility for wide range of contaminants. Furthermore, it may have some well stimulation effects. Return permeability testing of sandstone coring samples after immersion fluid completion Nitrate, in some conditions, showed some increase in the value of return oil permeability (Ko) from 25.55 to 36.25 mD.
In the field of applications, it has been tested as an additive and drilling mud on one of the deepest wells in Indonesia (5850 m) in Seram. As the additive, used in NaCl polymer mud system in order to reduce levels of solids and chloride, without changing the other mud properties significantly. With decreased levels of chloride, the corrosion rates of drilling and production equipments are also decreased. As a completion fluid, Nitrate CF have been used in the workover wells in South Sumatra and Riau. As a washer on perforation wash job, it is capable of delivering up to 20x increase in oil production and gas production compared to the previous 3x. Operationally, it has not been recorded for any Non Productive Time related this fluid.
Nitrate based fluid is an alternative completion fluid products that have been developed as an additive, mud drilling and stimulation fluids. Nitrate based fluid is sold in powder or liquid forms. Nitrates are also the basic ingredient of fertilizer. Nitrate Completion fluids have a density specification up to 1.75, the corrosion rate is lower than 10 MPY @350 deg F with standard carbon steel corrosion coupon, 5 NTU turbidity and pH 6-9, with pH buffering capacity, so it has a resistance to contamination of sour gas, having properties endotermic and environmentally friendly reaction.
High-temperature acidizing operations are challenging because of the highly corrosive nature of acids. Hydrochloric (HCl) acid has an especially high reaction rate, which increases the rate of tubular corrosion. In addition to the type and concentration of acids, factors such as temperature and metallurgy influence the rate of corrosion.
To meet increasing demand for deeper stimulation at high temperatures, emulsified acid is predominately used. It contains acid in the internal phase and oil in the external phase, forming an invert emulsion. The outer oil phase creates a barrier for acid, allowing its slow release for reaction with reservoir rock. Emulsified acid systems provide several advantages compared to plain acid. The oil barrier especially helps with preventing corrosion by significantly reducing the contact of acid with the metal tubular. High fluid viscosity helps reduce fluid loss, distributes the acid more uniformly in the formation, and reduces the rate of corrosion.
Selection of the proper corrosion inhibitor(s) is one of the most important criteria for high-temperature acidizing. The use of intensifier(s) with the inhibitor enhances the corrosion inhibition significantly. This makes it possible to use a higher concentration of HCl acid at temperatures as high as 350°F, thus enhancing the fluid efficiency. In this work, several corrosion inhibitors and intensifiers are studied at varied acid strengths and temperature conditions. To achieve good corrosion control, a synergy is required between corrosion inhibitors and corrosion inhibitor intensifiers. At the same time, they should not negatively impact the emulsion stability. A new emulsified acid system was developed using HCl acid strength up to 28%. High corrosion control imparted by inhibitor-intensifier synergy coupled with the slow reaction rate of emulsified acid makes this blend unsurpassed for use in extreme high-temperature conditions up to 350°F.
This emulsified acid system has the potential for use in the Khuff formation of Saudi Arabia with the addition of a H2S scavenger. Testing with a commercially available scavenger exhibited good compatibility with the blend.
Ma, He (King Fahd University of Petroleum & Minerals) | Sultan, Abdullah S. (King Fahd University of Petroleum & Minerals) | Shawabkeh, Reyad (King Fahd University of Petroleum & Minerals) | Nasser, Mustafa S. (Qatar University)
Surfactant and polymer flooding technology can greatly enhance the oil recovery through the expansion of sweeping and displacing efficiency. The recovered oil from surfactant and polymer flooding emulsifies the residual chemical, which makes the separation of water from oil quite difficult, yet the impact of the enhanced oil recovery (EOR) chemicals on the produced water cycle is generally neglected in chemically-based EOR studies. This includes compatibility of EOR chemicals with the additives used to pre-treat the injected water or change reservoir wettability and result in producing oil/water emulsion after EOR breakthrough.
The largest waste produced in oil and gas industries is believed to be the produced water, as it contains different sort of organic and inorganic admixture. There are a number of treatment methods available for produced water. To separate water from oil in a much efficient manner and to reach the emission standard, a new class of water soluble polymer of polyacrylamides (PAMs) with the addition of aluminum and ferrous sulphate were used as destabilizing agents for water/oil emulsions, which have been stabilized by surfactant (Tallowamine Acetate).
The impact of polyacrylamides with the addition of sulphates in turbidity reduction, COD, viscosity of volume separated water, and zeta potential were explored in this study. The effects of electrolytes such as aluminum sulphates and ferrous sulphate on produced water degree of flocculation in the existence of anionic polyacrylamide were investigated in terms of turbidity reduction and volume of separated water after jar test. Different concentrations of both sulphates added into optimum concentration polyacrylamide selected from jar test were utilized, and at optimum dosage, anionic AN 934 PAM with aluminum sulphate at its optimum concentration was proved as the best way to reduce the residual turbidity compared with other additives mentioned in this research. The results showed that the volume of separated water increased more than 25% compared when only PAMs were used, and the turbidity, viscosity, and COD reduction of separated water improved significantly. Addition of electrolytes such as aluminum sulphate and ferrous sulphate into polyacrylamide are both enhance the destabilization of water in oil emulsion in general compare to when only polyacrylamide used.
KOC and SGS performed a regional scale study to assess and forecast the H2S risk in the onshore sector of Kuwait. Based on KOC's comprehensive data base of H2S measurements, fluid chemistry, geochemical and lithological data, the H2S concentrations in the various hydrocarbon systems in Kuwait were mapped. The origin of the H2S in the Mesozoic reservoirs were analyzed and four major H2S systems were identified. The origin of the H2S in the Lower Jurassic is the TSR process with a pronounced regional trend of H2S concentrations increasing from 0.5% in the south up to 40% towards the north. The H2S encountered in the Upper Jurassic and Lower Cretaceous reservoirs originates from the cracking of sulfur in the Najmah source rock occurring during the early maturation process. The maximum H2S concentrations recorded in these systems does not exceed 5% and no regional trend of the concentrations is observed. The exceptions are overpressured carbonate stringers in the Upper Jurassic Gotnia and Hith formation which have local occurrences of more than 10% H2S. The Upper Cretaceous reservoirs in several oil fields show distinct H2S anomalies up to 5 %. Some of the anomalies possibly are related to field operation activities (e.g. injection) but also evidence for H2S migrated from deeper strata was found. Also indications for H2S scavenging in the Upper Cretaceous reservoirs was observed but could not be quantified. Some of the Tertiary heavy oil accumulations in the north which show high H2S concentrations could be related to the BSR process, however not all heavy oil reservoirs seem to be affected. A forecast of the future development of the H2S concentrations of each H2S system was performed.
This paper highlights the care to be taken by an Engineer while specifying and selecting a centrifugal compressor for CO2 compression.
With the increase in the levels of CO2 in the atmosphere, there is an increase in the popularity of capturing CO2 emitted from the large source points such as fossil fuel power plants, steel mills, cement plants, etc. before its release to the atmosphere and storing it under the geological formations (also used for Enhanced Oil Recovery (EOR) where possible). The compressors used to transport and store the CO2 at such depths need to compress the gas from atmospheric pressure to the pressures of the order of 200 bars or more.
The critical temperature of CO2 is only 31.1 deg. C, so the CO2 is generally transported and stored in supercritical state. The thermodynamic properties of supercritical CO2 are considerably different from the other real gases generally compressed. Further, to achieve this supercritical state, the critical point of CO2 is crossed somewhere in the compression stage. Near critical point, the ideal gas laws will not hold good for CO2. Moreover there is a reduction in the choke margin of the compressor due to the reduction of the sound speed in CO2, particularly near the thermodynamic critical point. Also the CO2 compressibility and specific heats are not linear near the critical pressure and temperature. The impurities in the CO2 will further affect the thermodynamic characteristics of the working fluid. Also the water content in the CO2 makes it extremely corrosive.
Considering all the aspects mentioned above, specifying the CO2 compressor correctly in terms of the equation of state to be used, the interstage pressures and temperatures to be maintained, suggesting the number of impellers per stage to maintain the desired flow coefficient, metallurgy to be selected and scheme of compressor dry gas seals, etc becomes all the more important and are described in the paper.
Laboratory testing of drilling/drill-in/completion fluids for evaluating formation damage potential requires return permeability tests. It is shown that the apparent shear yield stress of the filter cakes developed by these fluids at the wellbore interface determines the flow initation pressure and the near wellbore return permeabilities during onset of production.
Traditional bentonite clay based and recent non-damaging sized calcium carbonate polymer fluids were chosen to represent the wide variety of water-based drilling and completion fluids used in the field. A standard API filter cell was used with an over-balance of 100 psi and a filtration time of 16 hours for preparing the filter cakes. A constant strain rheometer was used to measure the filter cakes' apparent shear yield stresses. Linear strain and dynamic strain sweep tests were successfully conducted to get the estimates of the apparent shear yield stress of the prepared filter cakes.
Filter cakes prepared with bentonite muds showed an apparent shear yield stress of 800 Pascals (0.12 psi) while filter cakes of typical sized calcium carbonate drill-in fluids showed smaller apparent shear yield stress values between 250 and 450 Pascals (0.06 psi) varying with the median diameter of the calcium carbonate particles. The higher apparent shear yield stress of bentonite filter cakes was attributed to the smaller size of bentonite clay particles (< 2 microns) compared to the drill-in fluid sized calcium carbonate particles (> 2 microns). Two models were developed that used the apparent shear yield stress of these filter cakes and predicted the flow initiation pressures (FIP) and the return permeabilities. The models matched reasonably well with the experimentally measured FIP and return permeability ratios.
A novel approach for measuring and utilizing the apparent shear yield stress of filter cakes is presented that predicts FIP's and return permeability ratios during the onset of production. A new protocol is suggested that measures the filter cakes' apparent shear yield stresses to model the FIP and the return permeabilites for a given drilling and completion fluid.
The 8 TH reservoir is a "supermature" field which has been in production for more than 65 years. It was waterflooded for more than 50 years resulting in a current water cut of 96 %. The field contains medium viscous oil (in-situ viscosity 19 cP) and hence was considered for polymer injection despite the high water cut which was suggested by some authors to be challenging for polymer injection.
An inverted five spot unconfined polymer injection pilot was performed to reduce the subsurface uncertainties, determine if polymer flooding could lead to incremental oil in "supermature" fields, improve the operating and monitoring capabilities and improve the economic model for full-field implementation.
The results of the pilot show that an increase in 5- 10 % of the recovery factor can be achieved in the pilot area. The reasons for incremental oil production by polymer injection in this "supermature" field are acceleration along high permeable flow paths but more importantly substantial flow diversion in this heterogeneous reservoir. In the pilot area, the highest oil production since 1978 was achieved.
The main uncertainties related to surface handling of the polymer solution prior to injection, injectivity and incremental oil recovery could be reduced by monitoring of various parameters. In particular tracers and molecular weight distribution of polymers were measured to improve the understanding of the polymer solution effects on reservoir performance.
In addition, numerical simulations concerning injectivity and reservoir performance were performed to further improve the understanding of the processes and be able to optimize the operations. The simulations included polymer solution injection induced fractures as well as geological, reservoir fluid/relative permeability and polymer solution property uncertainties and allowed forecasting under uncertainty.
The cost structure of the polymer pilot was used to evaluate full-field economics taking learning curves, upscaling and costs optimisations into account.
Al-Zaabi, Asma Abdul-Rahman (ADMA-OPCO) | AL-Qamzi, Abdulla (ADMA-OPCO) | Said, Saad A. H. (ADMA-OPCO) | Angert, Patrick (ADMA-OPCO) | Ettireddi, Srinivas (ADMA-OPCO) | Kirkman, Matthew (ADMA-OPCO) | Uniyal, Suraj Mohan (Schlumberger) | Sami, Youssef (Schlumberger) | Jama, Ali Ahmed (Schlumberger)
Abu Dhabi Marine Operating Company (ADMA-OPCO) has made significant progress in its vision to develop Digital Oilfields in their new fields as part of the company’s new field development strategy alongside the implementation of new technologies and upgrades in mature Brownfields, as documented in SPE 171713 (ADIPEC 2014) and SPE 137668 (ADIPEC 2010).
The building of a historian system infrastructure foundation was the first step toward the automation of dataflow from various field assets to the company’s headquarters. This was essential to ensure verified, clean and accurate real time data are provided to users’ desktops.
The implementation of fit-for-purpose well-centric production workflows helped to realize the different needs of the production and reservoir teams, solving their day-to-day problems and optimizing field production. The workflows included String Status determination, Rate Estimation, Productivity Index Estimation and Well Model integration and Validation as well as Well Integrity Surveillance.
A gap though was recognized in delivering an easy to navigate, graphical, interactive, web based view of the combination of real time data, data from the company’s in-house developed production data management and accounting system, the corporate petro technical data archive and contextual data. A new visualization tool and modernised automated workflows were therefore developed and implemented on one of the company’s fields to address this challenge, the subject of this paper.
Current implementation includes a centralized, web-based integrated surveillance tool which is key to manage production performance and gain comprehensive insight into the operations through overall asset surveillance, quick analysis and reporting of key performance indicators including trends of actual production against plan, downtime analysis and well centric production workflows. A scalable, future proofed Field Surveillance Solution (FSS) was implemented. FSS has been built on top of a Production Operations Platform; which provides a single, integrated platform that connects operations for a broad range of disciplines. With cross-domain workflows and integration with other platforms and products, users can see their asset performance in a single environment, regardless of the asset type, size, or location.
FSS provided a state-of-the-art platform to visualize the data in an intuitive way simplifying the navigation from a high level overview of all company production to field level, followed by tower level and well level views in detail based on the historian live data and the company’s in-house developed production data management and accounting system.
This paper details the implementation of integrated field surveillance workflows to facilitate well and reservoir management for production optimization, reducing downtime, and faster decision making to improve overall operational efficiency.