Maintaining a stable borehole and optimizing drilling are still considered to be vital practice for the success of any hydrocarbon field development and planning. The present study deliberates a case study on the estimation of pore pressure and fracture gradient for the recently decommissioned Volve oil field at the North Sea. High resolution geophysical logs drilled through the reservoir formation of the studied field have been used to estimate the overburden, pore pressure, and fracture pressure. The well-known Eaton’s method and Matthews-Kelly’s tools were used for the estimation of pore pressure and fracture gradient, respectively. Estimated outputs were calibrated and validated with the available direct downhole measurements (formation pressure measurements, LOT/FIT). Further, shear failure gradient has been calculated using Mohr-Coulomb rock failure criterion to understand the wellbore stability issues in the studied field. Largely, the pore pressure in the reservoir formation is hydrostatic in nature, except the lower Cretaceous to upper Jurassic shales, which were found to be associated with mild overpressure regimes. This study is an attempt to assess the in-situ stress system of the Volve field if CO2 is injected for geological storage in near future.
This paper is based on the analysis of the ultrasonic/sonic data of the 9 5/8-in. casing logging of the 14 wells of the Varg field within the Norwegian Continental Shelf. While writing this papper Varg field was undergoing a plug and abandonment (P&A) phase after 19 years of production. High-quality bonding is observed behind the 9 5/8-in. casing far above expected theoretical top of cement within single casing areas. This bonding is attributed to the formation influence. Formation is used as an alternative to traditional cement barriers during P&A, and its use is regulated by the legislation.
The paper aims to develop better understanding of the mechanisms responsible for formation bonding development. The percentage of observed bonding at "high" and "high and moderate-to-high" quality is calculated within each well and is related to the various factors that could influence formation bonding development. Factors such as duration of time lapsed from well completion to well logging, type of well (producer versus injector), geological formation, type of drilling mud used, duration of production periods, volumes of production, and well deviation and azimuth were looked at to determine observable trends and relationships.
The results of the study allowed us to conclude which factors are critical or influence formation bonding. Based on the observations, recommendations can be made for the selection of the first well to be logged on the planned P&A campaigns. Correct selection of the first well saves time and resources on the formation testing for the qualification of the formation as a barrier.
Lescoffit, Severine Pannetier (Statoil ASA) | Houbiers, Marianne (Statoil ASA) | Henstock, Cris (CGG) | Hicks, Erik (CGG) | Nilsen, Karl-Magnus (CGG) | Hoeber, Henning (CGG) | Ratcliffe, Andrew (CGG) | Vinje, Vetle (CGG)
We have developed a time-lapse full-waveform inversion (4D FWI) workflow for permanent reservoir monitoring (PRM) data acquired over the relatively shallow, heavy-oil, Grane field in the Norwegian North Sea. The workflow was tested on elastic synthetic data representing two vintages of Grane PRM data, modeled with 4D changes in the velocity model derived from real reservoir modeling results, both in the overburden and at the reservoir level. These changes could be recovered, albeit not with as good resolution and magnitude as the true 4D effects. Application of the method to two vintages of real PRM data acquired in October 2014 and May 2015 is currently ongoing.
Presentation Date: Wednesday, October 19, 2016
Start Time: 1:30:00 PM
Presentation Type: ORAL
The managed pressure drilling (MPD) technique was chosen to drill a well on the Gullfaks A platform as a risk mitigating factor. In addition, the MPD technique gives accurate flow measurement, provides the potential to handle pressure variations quickly, and determines the drilling window. This paper presents the successful implementation of a sophisticated hydraulic model during planning and execution of a MPD operation in Gullfaks Well A-10B.
MPD service was delivered by a major service company with equipment coupled to a third-party real-time advanced transient hydraulic model. This model was used to calculate upstream choke pressure during MPD. It was also used in the planning stage to ensure operation was feasible within the pressure window with the selected fluids and drilling parameters. The system was run in automatic mode. Initially, only one section was planned for drilling in MPD mode. However, because of the losses observed and bottomhole pressure (BHP) flexibility provided by the MPD system, it was decided to drill the next section in addition to running and cementing the liner.
When the well was completed, three sections were drilled and two liners were run and cemented using MPD. The use of an automatic MPD system with a sophisticated hydraulic model helped ensure the well delivery was achieved according to plan without any major issues. The losses that occurred were detected and reduced significantly only by reducing the bottomhole target pressure. Dynamic drawdown tests in addition to a dynamic formation integrity test (FIT) confirmed the drilling window before drilling the second section. During the planning of cement job, a close working relationship between all parties was established in order to find the best possible solution for the well and achieve a delivery of a successful well. The planning tool used is a sophisticated hydraulic model that calculates a constant dynamic well pressure during the simulation of the cement job. The simulations were verified during the cementing job, with a good cement job as the result. Both liners were run and cemented with full returns and rotation.
This paper presents the challenges involved during this well project, how these challenges were handled by thorough planning, and finally the operational phase itself with focus on the MPD system, including the advanced flow model.
The towed streamer EM system makes it possible to collect EM data with a high production rate and over very large survey areas. At the same time, 3D inversion of the towed streamer EM data remains a very challenging problem because of the huge number of transmitter positions of the moving towed streamer EM system, and, correspondingly, the huge number of forward and inverse problems needed to be solved for every transmitter position over the large areas of the survey. We overcome this problem by exploiting the fact that a towed streamer EM system's sensitivity domain is significantly smaller than the area of the towed streamer EM survey. We apply the concept of moving sensitivity domain, originally developed for airborne EM surveys, to the interpretation of marine EM survey data. This makes it possible to invert the entire towed streamer EM surveys with no approximations into high-resolution 3D geoelectrical sea-bottom models. Our implementation is based on the 3D integral equation (IE) method for computing the responses and Fréchet derivatives for 3D anisotropic geoelectrical models. In the framework of the concept of the moving sensitivity domain, for a given transmitter-receiver pair, the EM responses and Fréchet derivatives are computed from a 3D Earth model that encapsulates the towed EM system's sensitivity domain. The Fréchet matrix for the entire 3D Earth model is then constructed as the superposition of Fréchet derivatives from all transmitter-receiver pairs over the entire 3D earth model. This makes large-scale 3D inversion a tractable problem with moderate cluster resources. We present case studies of 3D anisotropic inversion of towed streamer EM data from the Troll West Oil Province and Mariner field in the North Sea.
Towed streamer EM is a recently introduced acquisition system in the class of marine controlled source electromagnetic (mCSEM) technologies. The system architecture emulates 2D seismic with both the source bipole and the receiver streamer in a shallow tow behind the vessel. This facilitates dense subsurface sampling, acquisition speed at 4-5 knots, and it is fully combinable with 2D seismic acquisition at the same time for unprecedented efficiency. The dense data acquisition improves signal-to-noise (S/N), lateral and vertical resolution, and partly mitigates the non-uniqueness issue in the inversion. Previous systems have all been based on stationary recording nodes placed on the seafloor in a sparse line or 3D pattern, and with the source towed close to the seafloor.
Inversion of EM data is a much more computationally intensive process than the inversion of seismic data. Hence 1D and 2.5D inversions have been much more common than full 3D inversion. We have recently introduced cost effective 2.5D anisotropic inversion based on a finite element algorithm, and a highly efficient, comparatively low cost, 3D anisotropic inversion based on the integral equation. The cost savings in the 3D inversion originates in the application of a moving sensitivity domain approach, where the inversion is limited to a subsurface volume surrounding the source and receiver representing the volume that is actually sensitive to the source signal at any particular shot location. The sensitivity domain is then moving with the acquisition system. The Freshét derivatives in the inversion algorthim for the entire domain are then calculated only for the sensitivity domain for each shot, which reduces the computational time and memory consumption significantly. Acquisition is done by means of parallel 2D lines spaced approximately one km apart. This is sufficient data density to create 3D images of the vertical and horizontal resistivity in the subsurface.
Anisotropic inversion is a very important aspect, since the subsurface is always more or less anisotropic. Shales are intrinsically anisotropic and increasingly so with the degree of compaction. Cyclical sand/shale interbedding results in an effective anisotropy, and hydrocarbon-charged high resistivity sands interbedded with shales result in a very high effective anisotropy ratio. There is no accurate isotropic solution to an anisotropic subsurface.
Conventional node-based marine Controlled Source ElectroMagnetics (mCSEM) has considerable limitations in terms of data sampling density with typically 1-3 km between receiver nodes. The acquisition efficiency is also poor with the slow deployment and retrieving of the seafloor nodes, and a source towing speed of 1-2 knots, but surveying can be done in deep water. Towed streamer EM has the advantages of dense data sampling, 4-5 knots speed of acquisition, real-time quality control of source signal and incoming data, and simultaneous acquisition of seismic data. However the shallow tow, that facilitates the high acquisition speed, also means the water depth is limited to 400-500 m or too much signal is absorbed by the water column. The acquisition system is shown in Figure 1 below.
Simulation to Seismic (Sim2Seis) is a forward modeling technique used to predict/generate synthetic seismic response from a static or dynamic reservoir model. There are two key components of a Sim2Seis workflow: reservoir model (geological and/or simulation model) and petro-elastic models (PEMs). PEMs are rock physics functions which relate reservoir properties such as rock types, porosity and fluid saturation to the elastic properties such as compressional and shear velocities, and density. Predicted elastic properties are used to compute reflection coefficients, when convolved with a wavelet generate a synthetic seismic volume (1D or 3D).
There are several applications for Sim2Seis in reservoir characterization. It can be applied to test the consistency of a 3D geological static model, or of a history-matched simulation (dynamic) model with the actual seismic data. It can also be applied to study the impact of saturation change on seismic response (4D effect). A case study from an oil producing Tertiary age field in the North Sea was used to illustrate the applications of Sim2Seis workflow. This case study reveals the value of integrating the static and dynamic data for more accurate reservoir characterization, and consequently building a more reliable reservoir flow model which honors petrophysical and seismic data as well as production data.
The Alvheim Field is comprised of several hydrocarbon accumulations, known as Kameleon, East Kameleon, Boa, and Kneler which are located in Norwegian North Sea blocks 24/6 and 25/4 (Fig. 1), bordering the United Kingdom. Alvheim is located in the central part of Viking Graben where deepwater deposits of the Paleocene and Eocene (known as the Rogaland Group) have been the main exploration targets (Fig. 2). The main sediments present in the Rogaland Group (Fig. 3) are siliciclastics with minor coal, tuff, volcaniclastics, marls and reworked carbonate sediments which were sourced from the East Sheldland Platform. Coarser sediments were reworked and redeposited during three major episodes of sea level fall in this period (Brunstad et al., 2009). The main coarse clastic units of the Rogaland Group are Ty, Heimdal and Hermond Sandstones interbedded with Lista and Sele Shales. All producing fields within Alvheim are producing from the Palaeocene Heimdal Sand Member of the Lista Formation.
We introduce a method for integrating Towed Streamer EM and dual-sensor seismic data referred to as seismic guided EM inversion. The inversion workflow is initiated by adopting a sparse-layer depth model defined by dual-sensor seismic data to suggest resistivity boundaries without a rigid constraint. This makes good sense when considering the uncertainties in the seismic data from the time to depth conversion, and more importantly, the fact that a reservoir can be hydrocarbon-charged to an unknown degree corresponding to the spill-point or less. The anisotropic resistivity variations within the layers are accommodated by the lower and upper boundaries, which can be estimated by the unconstrained 2.5D anisotropic inversions. We describe in detail the workflow by applying it to a dataset example resulted from a complex geological region where the heavy oil fields known as Bressay and Bentley are located in the North Sea. Seismic imaging over these fields is challenging since they are rich in injectites, having steep and irregular features. There are also other resistive features such as the Balder tuff, granite intrusions and the basement that can interfere with a fully unconstrained EM inversion. The method introduced here is applicable for exploring complex geological regions, in particular in a frontier exploration, where CSEM and seismic data coexist.
These benefits are caused by the wider spectrum of broadband seismic relative to conventional seismic. Enhanced high frequency content leads to a sharper wavelet and therefore higher resolution images. Enhanced low frequency content reduces wavelet sidelobes, may eliminate the need for an interpolated well-logs low frequency model, and results in better signal penetration (see also ten Kroode et al., 2013). While the benefits of broadband seismic for impedance inversion and reservoir characterization were shown in the above cited studies, we are unaware of any study that details how to invert for the lowest frequencies present in the broadband data (2 - 5 Hz). This requires a longer wavelet than typically used for the conventional inversions.
Copyright 2013, Offshore Technology Conference This paper was prepared for presentation at the Offshore Technology Conference Brasil held in Rio de Janeiro, Brazil, 29-31 October 2013. This paper was selected for presentation by an OTC program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed by the Offshore Technology Conference and are subject to correction by the author(s). The material does not necessarily reflect any position of the Offshore Technology Conference, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Offshore Technology Conference is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of OTC copyright. Abstract The G-32 well was the first PWRI (produced water re-injector) to be drilled into the Heimdal Formation at the Grane oil field, located in the Norwegian Sea. Reservoir simulations suggested that G-32 would improve reservoir drainage in the area, providing an important increase in oil recovery through the nearby oil producers. The well was planned as a matrix injector rather than a fractured injector to optimize the reservoir drainage.