Øivind Fevang | Norwegian University of Science and Technology (original) (raw)

Papers by Øivind Fevang

Proceedings, Apr 24, 2017

Summary Declining oil production and increasing water cut in mature fields indicate the need for ... more Summary Declining oil production and increasing water cut in mature fields indicate the need for improved conformance control. In this paper we report on the numerical modeling performed to evaluate the in-depth water diversion pilot performed for the Snorre field, offshore Norway. For this pilot 240 000 m3 of a sodium silicate solution was injected in the period July to October 2013. The goal of the pilot was to form an in-depth flow restriction for improving the sweep. The setup, execution and measured data from response monitoring for the pilot have been presented in previous papers. As discussed therein, the operation clearly resulted in a strong in-depth flow restriction resulting in delayed tracer responses and decrease in the water cut. However, the monitoring was only limited to well observations, so to understand the spatial and temporal forming of the flow restrictions we had to rely on numerical simulation and modeling. In short, we calibrated simulation models to the observed well responses by introducing flow restrictions; i.e. using history matching techniques. Through the reservoir modeling work we reproduce the pilot response well by introducing sound flow restrictions. This gives us clear indications on the location, timing, strength and corresponding uncertainties of the introduced flow restriction. Moreover, the modeling work supports interpretations from the response monitoring program. Finally, in addition to help evaluating the performed pilot, the learnings from the modeling work will hopefully give more accurate evaluation of potential future water diversion candidates.

74th EAGE Conference and Exhibition incorporating EUROPEC 2012, Jun 4, 2012

All Days, Mar 31, 2014

Here we report on in-depth water diversion using sodium silicate to increase oil recovery at the ... more Here we report on in-depth water diversion using sodium silicate to increase oil recovery at the Snorre field, offshore Norway. A comprehensive qualification program revealed that the onset of gelation can be controlled; this was demonstrated in realistic core flood experiments as well as in a single well injection pilot. This paper highlights key design, response measurement plan and operational experiences from a large scale interwell field pilot of sodium silicate injection in a reservoir segment at the Snorre field on the Norwegian Continental Shelf. The operation of injecting 113 000 m3 preflush, 240 000 m3 sodium silicate and 49 000 m3 postflush was performed from June to October 2013. The goal is to create an in-depth restriction between a subsea water injection well and a platform oil producer with approximately 2 000 m well spacing, and thereby improve the reservoir sweep by water injection.To perform the field pilot a 35 000 ton shuttle tanker was converted to a well stimulation vessel with the necessary equipment to accommodate a higher number of people, a desalination plant, storage and mixing equipment and high pressure pumps. The vessel was connected directly to a subsea water injection well and injected during a period of 5 months. The chosen design was to (a) soften the formation water by a KCl preflush, (b) control the gelation kinetics using HCl acid as activator, mixed into the diluted silicate solution and (c) displace the silicate solution by a KCl postflush followed by seawater injection.The pilot injection operation is completed, and the displacement of the sodium silicate with following seawater injection to the planned position for in-depth plugging is still on-going. The operational success criteria of proving ability to perform large scale transport, mixing and injection of sodium silicate from a shuttle tanker directly into a subsea well with no near wellbore plugging is met. Future production response will reveal if the success criteria of in-depth plugging, improved reservoir sweep and decrease in water cut will be met.

All Days, 2016

Declining oil production and increasing water cut in mature fields highlight the need for improve... more Declining oil production and increasing water cut in mature fields highlight the need for improved conformance control. Here we report on a successful in-depth water diversion treatment using sodium silicate to increase oil recovery at the Snorre field, offshore Norway, utilizing a new operational concept of using a stimulation vessel as a platform for the large-scale injection into a subsea well. A custom modified 35,000 DWT shuttle tanker was employed for the field pilot. This paper describes the vessel preparations and the large-scale interwell silicate injection operation. The operational aspects of the large-scale interwell silicate injection include; identification of injection vessel requirements, major vessel modifications, chemical logistic, general logistics to site, major equipment set-up on vessel, subsea connection, mixing and pumping schedules, onsite QC, and real time monitoring. Experience from these operations and lessons learned are included in this paper. After th...

All Days, 2012

In-depth water diversion has been evaluated as a measure for increased oil recovery at the Snorre... more In-depth water diversion has been evaluated as a measure for increased oil recovery at the Snorre field, offshore Norway. The waterflood sweep efficiency can be potentially increased by in-depth placement of a blocking agent. From a comprehensive qualification program presented in a previous work (SPE 143836) in-depth formation plugging was demonstrated in realistic core flood experiment using sodium silicate. This paper highlights key results obtained from a single well pilot injection of sodium silicate in an offshore well at the Snorre field at NCS. The injection pilot was carried out successfully in June 2011 with the goal to confirm the ability of generating an in-depth permeability restriction approximately 40 m away from the wellbore. Fluids mixing and injection were performed from a vessel linked up to the platform in order to minimize the operational interference with the ongoing work on the platform. The chosen pilot design was aimed to (a) soften the formation water by a ...

This paper presents a generalized treatment of wells in a reservoir simulator which accounts for ... more This paper presents a generalized treatment of wells in a reservoir simulator which accounts for localized near-wellbore multiphase flow behavior using a pseudopressure approach. The method has its most important application to gas condensate wells where condensate blockage can have a significant impact on well deliverability. The formulation is general, however, in that it handles all reservoir fluid systems from single-phase gas to saturated volatile oils to undersaturated black-oil oils. INTRODUCTION The procedures presented are designed to compute the relation between molar or volumetric rate (q) from a well grid block and the grid-blocks’s flowing bottomhole pressure (BHFP). The pseudopressure method is accurate for the treatment of varying (and sometimes highly non-linear) total gas+oil mobilities within a well-grid cell, independent of the well completion geometry. The method presented is based on the work on gas condensate wells presented in Ref. 1 by Fevang and Whitson. The...

This paper gives a review of the key PVT data dictating recovery and well performance of gas cond... more This paper gives a review of the key PVT data dictating recovery and well performance of gas condensate reservoirs. The importance of specific PVT data are put in the context of their importance to specific mechanisms of recovery and flow behavior. Phase behavior important to gas cycling projects is also covered. Modeling gas condensate reservoir fluid systems with an equation of state is discussed, as is EOS modeling of complex fluid systems with strongly varying compositions and PVT properties.

SPE Annual Technical Conference and Exhibition, 2000

Transport in Porous Media, Jul 31, 2003

Journal of Petroleum Science and Engineering, Apr 1, 2005

The principal depletion drive mechanism is the expansion of oil and gas initially in the reservoi... more The principal depletion drive mechanism is the expansion of oil and gas initially in the reservoir—neglecting water influx. The main factors in depletion drive reservoir performance are total cumulative compressibility, determined mostly by initial composition (gas–oil ratio), saturation pressure, PVT properties, and relative permeability. In this paper, we systematically study the effect of initial composition on oil recovery, all other

Proceedings of SPE Annual Technical Conference and Exhibition, 2000

Proceedings of Abu Dhabi International Petroleum Exhibition and Conference, 2002

This paper describes the development of an equation of state (EOS) for a gas injection simulation... more This paper describes the development of an equation of state (EOS) for a gas injection simulation study of a compositionally-grading near-critical oil reservoir. As the number of initial oil sample was limited and no gas-cap gas compositional data was available, the equilibrium contact mixing (ECM) test was used to (a) help tune the EOS to nearcritical phase equilibrium existing at the near-critical gas-oil contact, and (b) to estimate the initial gas-cap PVT properties. Available standard depletion type PVT data, multi-contact swelling test data, slim tube test data and ECM data were used in the development of the full-fluid "detailed" EOS using 16 components. Characterisation of the C7+ fraction together with regression of EOS parameters was carried out to tune the fluid model to match all available measured PVT data. Isothermal compositional gradient calculations were performed for all available samples and then a sample was selected to best represent the most important measured properties such as saturation pressure, saturated density and the compositional gradients in the reservoir. Equilibrium contact mixing data provide key gas-cap gas properties and vapour/liquid phase equilibria data for developing the EOS, also important for studying near-miscible gas injection processes. Introduction Characterising fluid properties is an essential task for gas injection studies. The composition of initial gas-cap gas is needed to quantify initial condensate in place, and it may impact mixing of injection gas in updip injectors. For nearcritical compositionally-grading systems, the estimation of gas-cap gas composition may be important in studying developed miscibility. The gas-cap gas composition may be estimated from compositional gradient calculations from a down-dip oil sample, however this may lead to considerable uncertainties unless the EOS model has been tuned to nearcritical phase data. In this study we used the equilibrium contact mixing method to obtain equilibrium gas and oil compositions at conditions similar to what are expected at the gas-oil contact. Once tuned to the ECM data, the EOS model is expected to predict more accurately the compositional gradient, gas-oil contact (GOC) location, and gas compositions within the gas cap. This paper provide guidelines for selecting fluid samples and for proper development of an accurate EOS to handle compositional grading calculations and phase behaviour changes in a gas injection project. Measured Oil and Gas PVT data There were 20 fluid samples from 13 different wells including 36 constant composition expansion (CCE) tests, 18 differential liberation expansion (DLE) tests, 60 multi-stage separator (SEP) tests, 4 multi-contact swelling (MCV) tests and 3 slimtube (SLM) tests. Since no representative gas cap sample was available, the ECM test1 was carried out to provide estimates of GOC oil and gas compositions at initial condition, and to determine the richness of the gas-cap gas. This data, when used to tune the EOS model, also provides more certainty that compositional gradients are reliable. A schematic diagram of the ECM test procedure is shown in Fig. 1. Separator samples were collected from an oil well coning gas-cap gas during testing. The separator samples were then recombined in a proportion which resulted in approximately 50% by volume of equilibrium gas and equilibrium oil at expected initial reservoir conditions near the gas-oil contact. The system was allowed to equilibrate for 24 hours after physical agitation, then the two equilibrium phases were removed separately from the PVT cell for compositional and PVT data measurements. The resulting equilibrium phases are assumed to provide reasonable estimates of the initial GOC fluids; even if they are not very close to the actual GOC fluidsa, the EOS was tuned to these data so that calculated GOC compositions from an isothermal gradient calculation would be more reliable. Measured Oil and Gas PVT data There were 20 fluid samples from 13 different wells including 36 constant composition expansion (CCE) tests, 18 differential liberation expansion (DLE) tests, 60 multi-stage separator (SEP) tests, 4 multi-contact swelling (MCV) tests and 3 slimtube (SLM) tests. Since no representative gas cap sample was available, the ECM test1 was carried out to provide estimates of GOC oil and gas compositions at initial condition, and to determine the richness of the gas-cap gas. This data, when used to tune the EOS model, also provides more certainty that compositional gradients are reliable. A schematic diagram of the ECM test procedure is shown in Fig. 1. Separator samples were collected from an oil well coning gas-cap gas during testing. The separator samples were then recombined in a proportion which resulted in approximately 50% by volume of equilibrium gas and equilibrium oil at expected initial reservoir conditions near the gas-oil contact. The system was allowed to equilibrate for 24 hours after physical…

SPE Annual Technical Conference and Exhibition, 2007

... Tim Isom and Helene Moseidjord are greatly appreciated for their help for part of data collec... more ... Tim Isom and Helene Moseidjord are greatly appreciated for their help for part of data collection, modeling, and paper proof-reading. We would like to thank Aaron Zick for using his algorithm to check LBC polynomial monotonicity.19 Nomenclature a = Lohrenz-Bray-Clark ...

SPE Reservoir Engineering, 1996

Summary This paper gives an accurate method for modeling the deliverability of gas-condensate wel... more Summary This paper gives an accurate method for modeling the deliverability of gas-condensate wells. Well deliverability is calculated with a modified form of the Evinger-Muskat1 pseudo pressure (originally proposed for solution-gas-drive oil wells). The producing gas/oil ratio (GOR) is needed to calculate pseudo pressure, together with pressure/ volume/temperature (PVT) properties (black-oil or compositional), and gas/oil relative permeabilities. The proposed method is successfully tested for radial, vertically fractured, and horizontal wells. Using the proposed deliverability model, we show that fine-grid single-well simulations can be reproduced almost exactly with a simple rate equation that uses pseudo pressure. The key is knowing the producing GOR accurately. The effect of near-wellbore damage, vertical fracture, or flow improvement caused by horizontal well trajectory is readily incorporated into the rate equation as a constant skin term. The effect of gas/oil relative permea...

European Petroleum Conference, 1994

This paper describes experimental procedures for determining accurate estimates of original insit... more This paper describes experimental procedures for determining accurate estimates of original insitu reservoir oil and gas compositions. The proposed equilibrium contact miring (ECM) method can use samples which are clearly not representative of insitu fluids (e.g. due to near wellbore multiphase behavior, reservoir depletion, or separator sampling problems). ECM procedures are recommended for saturated, undersaturated, and depleted reservoirs. Examples are given for reservoir fluids ranging from very lean-gas/black-oil systems to highly volatile gas/oil systems. Furthermore, it is shown that the proposed ECM method can be used to obtain depth-weighted average insitu compositions in reservoirs with gravity-induced vertical compositional gradients. The Peng-Robinsen (PR) and Soave-Redlich-Kwong (SRK) equations of state (EOS) are used in calculations, with extensive characterization of the C7+ fractions. Static PVT experiments and radial 1D/2D compositional simulations of typical fluid-sampling conditions are used to verify the proposed methods. Partly due to the success of the ECM method, the traditional definition of a "representative" sample is reconsidered, and a more general definition is recommended. The general definition ("reservoir- representative") is any sample produced from a reservoir, where the measured composition and PVT properties are of good quality. The traditional definition ("insitu representative") is a special case where the sample represents an insitu reservoir composition at a specific depth (or an average composition for a depth interval). Separator sampling of gas condensate and volatile oil reservoirs is widely used. We present an analysis of traditional separator sampling methods, potential errors in separator sampling, and a critical evaluation of the "isokinetic" sampling method. Isokinetic sampling is currently used to sample separator gas streams when separator liquid "carryover" is suspected. Problems with the isokinetic method are discussed, and we suggest field and laboratory measurements which are needed to confirm the validity of isokinetic sampling. Introduction Historically, the only acceptable method for determining initial reservoir compositions has been to directly obtain bottomhole or recombined separator samples which truly represent insitu compositions. Sampling procedures have been developed to assist in obtaining insitu-representative samples, but for reservoirs that are initially saturated or only slightly undersaturated, it may be impossible to obtain such samples. When flowing bottomhole pressure drops below the reservoir fluid's saturation pressure, multiphase behavior near the wellbore may result in mixtures flowing into the wellbore which are clearly not insitu representative. When reliable insitu-representative samples can not (or have not) been obtained early in the life of a reservoir, considerable uncertainty in initial hydrocarbons (oil and gas) in place may exist. One consequence is that process facilities may need to be overdesigned to account for these uncertainties. Accurate insitu-representative samples are particularly important for gas condensate reservoirs where significant income may come from processed LPGs, NOLs, and stabilized condensate. Obtaining accurate insitu oil composition early in the life of a reservoir is not usually a problem even when flowing bottomhole pressure drops below the original bubblepoint Separator samples can be recombined in a ratio (not necessarily the same as measured during sampling) that yields a bubblepoint pressure equal to the reservoir pressure at the gas-oil contact (GOC). This approach generally works well, mainly because separator gas and separator oil compositions are relatively insensitive to multiphase effects near the wellbore. A problem in many older oil reservoirs is that samples were not collected initially (e.g. many West Texas CO2 candidate reservoirs). No generally-accepted procedure has been published for determining the initial oil compositions in depleted reservoirs. Usually the only alternative is to recombine currently-producing separator oil and separator gas samples in a ratio that yields the initial reservoir bubblepoint pressure. P. 239^

SPE Europec/EAGE Annual Conference, 2012