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.
The objective of this paper is to demonstrate how advancedrealtime monitoring (ARM) utilizing advanced hydraulic and mechanical modelling of the drilling process provided early detection of anomalies by giving diagnostic messages during drilling operations. These achievements can minimize non-productive time and invisible lost time and maximize the benefits and value of operations; if they are utilized to its full potential by operations. Some well cases are used to illustrate the methodology and its results. Among problems diagnosed are losses, stuck pipe during drilling and casing running, downhole equipment leakage and improper hole cleaning. In some cases, action was taken based on the diagnostics; and the operational conditions were modified to mitigate the situation. In other cases, the warnings were not taken seriously, the situation worsened until the problem was irreversible and a stuck situation occurred. In one well presented in the current study a stuck pipe situation happened during drilling 8½" section which led to a downtime of more than 20 days. By utilizing the ARM, it couldhave been possible to detect some early signs of the stuck conditions in the wellbore and avoid it. Another stuck situation in awell during 14-inch Casing running, led to downtime of more than 10 days which involved breaking out the casing above the stuck point and performing P&A. The ARM provided early signs of stuck casing that was about to occur, and these signs first started appearing about 15 hours before the pipe got completely stuck. This paper will present the Advanced realtime Monitoring ARM System and the modelling behind this. Also, the plans for further implementation and integration of this in the work processes will be discussed, before results from the first year of utilization will be presented with examples.
With an increasing focus on identifying cost-effective solutions to well design with a minimal impact on productivity, this paper will focus on an alternative to cesium (Cs) formate as the perforation fluid in the high-pressure/high-temperature (HP/HT) Gudrun Field operated by Equinor. Cs formate has been used with success for drilling and perforating many HP/HT wells. However, because of the significant cost of this fluid coupled with low oil prices, Equinor wanted to perform testing to assess the performance of an alternative oil-based mud (OBM) as a perforation fluid. In this paper we describe the extensive qualification testing that we have conducted, which includes coreflooding using representative plugs from Gudrun Field under downhole temperature and pressure conditions. In addition, eight API RP19B (2014) Section IV perforation tests have been conducted to compare the performance of the Cs formate with the OBM. These tests were undertaken using gas- and oil-saturated cores to reflect different production scenarios. The main aspects of the perforation operation that were reflected in the test design were as follows:
On the basis of the results of the coreflooding combined with the API RP19B (2014) Section IV testing, the OBM was selected as the perforating fluid for use on Gudrun Field. The perceived benefits of using the OBM were as follows:
Perforation modeling is described, and a comparison is made between this and the API RP19B (2014) Section IV tests. Finally, the well-startup experiences and the production data are presented, demonstrating the effectiveness of the OBM as a perforation fluid.
Summary A new approach to inversion of velocity data (Velocity Inversion) is presented, where the input is high resolution velocities from modern broadband seismic. The present study is from the central part of the Norwegian North Sea. It focuses on lithology and porosity estimation for exploration, with particular attention to Jurassic and Tertiary sandstones. Velocity Inversion method is robust, simple to calculate and gives reliable results that can be controlled with well data. The quality of the result is seismic velocity resolution depended.
With increasing focus on identifying cost effective solutions to well design with minimal impact on productivity, this paper will focus on an alternative to cesium formate as perforation fluid in the HPHT Gudrun field operated by Statoil. Cesium formate has been used with success for drilling and perforating many HPHT wells. However, given the significant cost of this fluid coupled with low oil prices, Statoil wanted to perform testing to assess the performance of an alternative low ECD oil based mud as a perforation fluid. The paper will describe the extensive qualification testing that has been performed. This includes coreflooding using representative plugs from Gudrun under downwhole temperature and pressure conditions. In addition, eight Section IV perforation tests have been performed to compare the performance of Cs formate and the low ECD oil based mud. These tests were undertaken using gas and oil saturated cores to reflect different production scenarios. The main aspects of the perforation operation that were reflected in the test design were as follows. Perforating at reservoir pressure and laboratory testing temperature of approximately 100°C Simulating an extended shut in period after perforation Undertaking a clean up sequence using scaled down flowrates
Perforating at reservoir pressure and laboratory testing temperature of approximately 100°C
Simulating an extended shut in period after perforation
Undertaking a clean up sequence using scaled down flowrates
Based on the results of the coreflooding combined with the section IV 19B testing, the low ECD OBM was selected as the perforating fluid for use on Gudrun. The perceived benefits of using the low ECD OBM were as follows. Simplification: use of the same fluid for drilling and perforating the reservoir section. Tangible cost savings in fluid cost and time savings of approximately 40M NOK ($5M). Potentially increased productivity compared to cesium formate. Improved standardization of the operational sequence.
Simplification: use of the same fluid for drilling and perforating the reservoir section.
Tangible cost savings in fluid cost and time savings of approximately 40M NOK ($5M).
Potentially increased productivity compared to cesium formate.
Improved standardization of the operational sequence.
Perforation modelling is described and comparison is made between this and the Section IV tests. Finally, the well start-up experiences and production data are presented demonstrating the effectiveness of the low ECD oil based mud as a perforation fluid.
ABSTRACT: Shale cap rocks are nature’s best hydraulic barrier geomaterials. They are effective seals for underground hydrocarbon bearing formations as well as CO2 storage formations in carbon capture and storage (CCS) projects. The sealing properties of shale rocks are directly related to its minerals and the internal arrangement of clay and non-clay minerals. This is known as the microstructure. Since shales are predominantly composed of clay minerals, the type and amount of clay minerals contained within the rock are the key factors of its sealing properties. The goal of this study is to gain a better understanding of how different types of clays behave in a typical CO2 storage reservoir condition.
Clay minerals have layered structures which often carry negative surface charges. The combination of large reactive surface areas and charge bring complexity in terms of their reactivity to fluids. Therefore, even the same type of clays can have different properties depending on their depositional environment, which was influenced by different fluid properties (pH, T, P, salinity). The same is also true of the exposure of clay-rich rocks to reactive fluids during geologic times as well as under subsurface engineering conditions (nuclear waste storage, injection of waste water and fracking fluids in oil&gas, and carbon sequestration). For this study, artificial shale rock samples were designed using purified natural minerals in different ratios. These samples allowed us to observe the impact of the mineralogical composition on mechanical properties and obtain a systematically quantified comparison between samples. Indentation tests were conducted to evaluate changes in mechanical properties as a result of composition alteration, while Scanning Electron Microscopy (SEM) was used to probe any changes to microstructures. Observations in this study indicate: a) high clay content shale formation has better sealing properties because its mechanically more stable and has lower permeability due to the low porosity; b) increasing the salinity of pore fluid can decrease the thickness of double layers of clays, causing an increase in permeability because of the increase of effective porosity. Salinity has an additional weaker effect on the mechanical properties because as the sample dries, salt crystallized within the sample and creates an internal expansion force resulting in integrity failure.
Caprocks are essentially defined as low permeability formations, and sometimes, but not necessarily, with low porosity. More than 60% of effective seals for geologic hydrocarbon bearing formations which act as natural hydraulic barriers constitute shale caprocks (Allen and Allen, J.R., 2005). The effectiveness of cap rock depends on its ability to immobilize fluids, which include a low permeability and resilience to the in-situ formation of fractures as a result of the pressurized injection. The alteration in sealing properties of shale rocks is directly related to the differences in its mineralogical composition and microstructure.
Ramstad, Kari (Statoil ASA) | McCartney, Ross (Oilfield Water Services Limited) | Aarrestad, Henriette Dorthea (Statoil ASA) | Lien, Siv Kari (Statoil ASA) | Sæther, Øystein (Statoil ASA) | Johnsen, Rita Iren (Statoil ASA)
The Johan Sverdrup field will, at maximum, contribute 25% of the total oil production from the Norwegian Continental Shelf (NCS). Plateau production from the fully developed field is estimated at 550,000 to 650,000 BOE/D. Geochemical formation-water interpretation and development of a scale-management strategy have been performed to ensure high well productivity and process regularity of the field.
Uncertainty over the composition of formation water made the decision to inject normal seawater or low-sulfate seawater into the reservoir for pressure support a challenge. Water compositions in samples obtained from appraisal wells were unusual for the Norwegian North Sea, being sulfate-rich with negligible barium. This was suspected to be an artifact of drilling-fluid contamination, and corrections were applied to obtain representative estimates. These estimates confirmed that the formation waters had variable salinity (21–48 g/L chloride), and were indeed sulfate-rich (94–746 mg/L) and barium-depleted (<6 mg/L). The compositions may reflect (a) mixing of formation waters across the field over geological time and/or (b) interactions with the underlying Zechstein group (anhydrite). The focus here is on issue (b) because a detailed evaluation of local/regional aquifer movements in geological time, communication patterns, and flow restrictions is beyond the scope of this paper.
Three appraisal wells in the Geitungen Terrace showed barium-rich formation water outside the main reservoir area where no underlying Zechstein group was present. Initially, there were concerns about the scaling risks associated with mixing sulfate- and barium-rich formation waters. However, present geological understanding indicates insignificant aquifer volumes with barium, implying that full-field development and scale strategy do not need to consider barium-rich water.
Scale predictions were performed for various strategies: formation-water production, seawater injection, produced-water reinjection, and low-salinity/low-sulfate-water injection. Moderate strontium sulfate (SrSO4) and calcium carbonate (CaCO3) scalings are expected in the production wells. If third-party barium-rich waters are tied in, the topside barium sulfate (BaSO4) scaling risk increases.
This work has shown
The implications for field development are
Spectral decomposition is applied to stacked seismic traces to enable low-frequency analysis and comparison of results from the two oil-bearing reservoirs. To look for low-frequency anomalies, we have used spectral sections of 5 Hz to 40 Hz. Additionally, in order to analyze anomalous low-frequency responses, so-called frequency gathers (amplitude vs time in various narrow frequency bands) at a single seismic trace or well location have been used. This study focuses on finding a connection between the occurrence or nonoccurrence of lowfrequency anomalies and the nature - heterogeneous or homogeneous - of the reservoir. Here, Johan Sverdrup is considered a relatively homogeneous reservoir while the 2/7-31 discovery in Western Graben is considered a relatively heterogeneous reservoir. Introduction Accumulating evidence suggests that hydrocarbons often exhibit a low-frequency anomaly in seismic data. Extraction of the frequency components of seismic waves by spectral decomposition can be carried out by a number of algorithms.
Constable, Monica Vik (Statoil ASA) | Antonsen, Frank (Statoil ASA) | Stalheim, Stein Ottar (Statoil ASA) | Olsen, Per Atle (Statoil ASA) | Fjell, Oystein Zahl (Statoil ASA) | Dray, Nick (Statoil ASA) | Eikenes, Sigurd (Statoil ASA) | Aarflot, Haakon (Statoil ASA) | Haldorsen, Kjetil (Statoil ASA) | Digranes, Gunnar (Statoil ASA) | Seydoux, Jean (Schlumberger) | Omeragic, Dzevat (Schlumberger) | Thiel, Michael (Schlumberger) | Davydychev, Andrei (Schlumberger) | Denichou, Jean-Michel (Schlumberger) | Salim, Diogo (Schlumberger) | Frey, Mark (Schlumberger) | Homan, Dean (Schlumberger) | Tan, Sarwa (Schlumberger)
A vision in the oil industry for decades is becoming a reality. Finally, we are able to drill and react proactively to formation resistivity properties several meters ahead of the drill bit, instead of reacting to measurements behind the bit. Through a technology collaboration between operating and service companies, a targeted technology development for measuring resistivity contrasts ahead of the bit in real time to reduce cost and risk during drilling operations was developed. Two electromagnetic look-ahead (EMLA) prototypes have been developed for 12¼- to 14-in. boreholes. The EMLA tool is modular and consists of a low-frequency transmitter inserted in the rotary steerable drilling assembly 1.8 m behind the bit and two to three receivers spaced out in the drillstring. The EMLA tool uses the same sensor technology and operates with the same multispacing and multifrequency measurements as the commercial ultradeep “look-around” directional resistivity tool. The formation structure ahead of the bit is interpreted by inversion to differentiate sensitivity around the tool from effects ahead of the bit. The look-ahead capability is dependent on the transmitter-receiver spacing, frequency, resistivity around the tool, thickness of the target, and the resistivity contrast ahead of the bit.
The EMLA tool provides a step change with regard to precision in detecting changes in resistivity properties ahead of the bit in vertical and low-angle wells. The ability to react to resistivity contrasts ahead of the bit has a direct impact on how wells are drilled. The main application of EMLA to date has been to drill the well section above the reservoir closer to top of reservoir to avoid complications in the shale above the reservoir, as presented in two case studies. Challenges related to salt drilling are addressed in another case study where the salt exit was detected 30 m ahead of the bit. Improved precision in coring-point selection is another potential application.
When considering the task of creating reservoir models for fields under development, dynamic data measurements often have limited impact compared with static (geophysical and geological) data. This is not necessarily true for the Johan Sverdrup field offshore Norway, where exceptional reservoir properties make the data from eight drill-stem tests (DSTs) particularly interesting. For this reason, it is important to utilize the information found in the collected static and dynamic data in a consistent manner, to improve the understanding of the reservoir. This is especially true for the Avaldsnes High area, located in the southeastern part of the Johan Sverdrup field, where the observed thickness is below the seismic resolution, and the DST data from four wells indicate permeabilities in the range of 20 to 80 Darcy, with an overlapping radius of investigation.
In this paper, we apply an ensemble-based approach to generate a large set of reservoir models for the Avaldsnes High area of the Johan Sverdrup field, all of which are plausible given the current observed static and dynamic data. We consider multiple modelling scenarios, introducing uncertainty in the sand thickness, facies (rock type) description and the permeability modelling. Unlike conventional pressure transient analysis (PTA), where we analyze the DSTs separately, and the non-uniqueness in the data interpretation is hard to address and quantify, this is not the case with the ensemble-based approach. Since we conduct the static and dynamic data conditioning simultaneously, we can consistently address possible ambiguities in interpreted permeabilities, thicknesses and flow barriers seen in the conventional PTA analysis. The study reveals that by conditioning the generated models to dynamic data we introduce clear spatial trends in both the sand thickness and permeability. In particular, we greatly reduce the potential downside with respect to the sand thickness in the Avaldsnes High area.