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.
ABSTRACT: The ability of shale formations to deform and seal the annulus around the casing has been documented in publications and industry presentations. Moreover, development of such natural seals (barriers) in the annulus has been utilized in Permanent plug and abandonment (PP&A) operations as an alternative to conventional PP&A methods and materials. It has been reported that this in fact facilitated the PP&A operations and resulted in considerable cost savings. The objective of this paper is to present the work done to assess the potential of the Gearle formation in the Griffin fields in the southern Carnarvon Basin in Western Australia with respect to its ability to provide a barrier during the PP&A operations. For this purpose, we identify first and second order factors controlling the creep deformation of shales/mudstones. In turn, we compared the material and mechanical properties of Gearle formation with the formations forming seal at NCS and also with other measurements completed on other shales globally. In addition, we have utilized simple numerical creep models to assess the creep potential of Gearle formation to form a barrier around the casing. Later during PP&A operations, we acquired IBC-CBL-VDL logs in the wells and observed evidence of bonding. We, finally, present the cement log bond interpretations in the intervals we observed casing-formation bonding.
Permanent plug and abandonment (PP&A), as common industry practice, is performed by setting a number of cement plugs inside the casing strings. In certain cases, annular seal, traditionally provided by annular cement, may not fulfil the abandonment requirements and rather costly remedial cementing, milling or cut and pull of casing has to be performed in order to complete the PP&A of a well. However, certain rock types, i.e., shale and salt, have the potential to satisfy the requirements for PP&A and can therefore be used as well barrier elements as long as they can be proven to have the required strength and seal around the casing over a sufficient interval. In particular, the ability of shale to deform and seal the annulus around casing to form a barrier has been documented with the experience of operators in the Norwegian Continental Shelf (NCS) in the North Sea -providing ease of operations and cost savings (Carlsen, 2012, Williams et. al, 2009).
This case study aims to share the experience and improve the understanding of downhole shock and vibration and demonstrate how it can be prevented using thorough offset analysis, an advanced bit design, downhole mechanics module, and detailed drilling roadmap. The new approach delivered a step change in the performance of the 17 ½-in. section in Valemon field, in the Norwegian sector of the North Sea. Employing a one-run strategy through this extremely demanding section could eliminate the need for a dedicated motor run to withstand high shocks through the sandy interval with interbedded limestone and cemented sand layers. Using a point-the-bit bottomhole assembly (BHA) with a detailed drilling roadmap for every group of formations secured smooth drilling, pull out, and running of the intermediate 14-in. × 13 3/8 in. casing to provide integrity to drill 12 1/4-in. section.
An advanced bit design balanced drilling with low aggressiveness through sand without compromising the performance through the interbedded limestone stringers and claystone. The conical-shaped cutter placed behind the main PDC conventional cutters successfully controlled the depth of cut through the sandy intervals and mitigated the downhole shocks.
A detailed drilling roadmap was developed to define formation-specific drilling parameters to mitigate the shock-related failures on similar lithology.
A downhole drilling mechanics module was used to provide real-time axial, lateral, and torsional shock and vibration data, which enabled adjustment of surface drilling parameters accordingly.
The Gullfaks Shetland Group and Lista Formation (Sh/L) are fractured chalk reservoirs located above the main Gullfaks reservoirs. Fractured carbonate reservoirs are heterogeneous, due to deposition, diagenesis and fracturing, so they are challenging to characterize and model. Shetland/Lista is considered to be a type II reservoir, according to the Nelson classification (
Production by depletion started late 2012. Historical out of zone injection that occured some time between 1994 and 2010 from the Gullfaks main reservoirs increased the reservoir pressure in Sh/L. Production from Sh/L therefore initially improved the drillability to the underlying Gullfaks main reservoirs. However, presently further reduction of the pressure is not advisable to preserve the drillability. Most of the Shetland producers are consequently shut-in. Water injection to maintain the pressure is therefore considered to be a promising new drainage strategy.
In addition to pressure support, fractured, water-wet reservoirs can benefit from water injection through increased oil recovery by spontaneous imbibition. Oil can be mobilized by spontaneous water imbibition from fracture to matrix.
Special core analysis experiments indicated water-wet conditions and potential for oil recovery by spontaneous imbibition in the Shetland reservoir. Complementary field tests were conducted to confirm this:
A single well injection and following production test (push-and-pull) with tracers, confirmed high potential for spontaneous imbibition. A multi-well pilot also showed clear indications of imbibition taking place between injector and producers, when analysing production and tracer data.
A single well injection and following production test (push-and-pull) with tracers, confirmed high potential for spontaneous imbibition.
A multi-well pilot also showed clear indications of imbibition taking place between injector and producers, when analysing production and tracer data.
The objective of the work described in this paper is to confirm feasibility of a new drainage strategy, and confirm that pressure support by water injection will be beneficial for the oil recovery in the Shetland/Lista reservoirs through imbibition.
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.
Hansen, Jørgen André (University of Oslo) | Yenwongfai, Honore (University of Oslo and Statoil ASA) | Fawad, Manzar (University of Oslo) | Mondol, Nazmul (University of Oslo and Norwegian Geotechnical Institute)
We present a quantitative estimate of exhumation in the Central North Sea by examining depth trends of velocity and density data compared to experimental compaction trends. Additionally, seismic inversion and attribute application from the study area is shown as an example of the connection to future work on quantitative analysis of source and reservoir rocks. Rock physics relations are demonstrated to be important for all parts of the study. Introduction Cenozoic exhumation affecting the Norwegian Continental Shelf (NCS) is well established and has been described in various publications over the last decades (e.g.
Subsurface generation of hydrogen sulphide (H2S), commonly known as reservoir souring, is a clearly identified but, still not fully understood phenomenon associated with water injection for secondary oil recovery. A large number of North Sea fields have been under seawater injection for many years, yet the majority are relatively poorly documented in terms of how and when souring developed and the amount of H2S being generated between injector and producer well pairs.
As part of ongoing work to verify the results of reservoir souring simulations, using empirical data, an exercise was undertaken to collate souring information from a number of older fields, with the objective of attempting to identify trends in, or factors impacting, souring development. A review of available historic data from the Gullfaks field was made; linking measured H2S values, well test data, water analyses and tracer data to identify long term souring patterns, the amount of H2S produced relative to injected water and to determine the effectiveness of the different mitigation strategies used in the field. The Gullfaks field in the Norwegian sector of the North Sea began production in 1985 and has been widely cited in connection with the introduction of nitrate treatment as a mitigation method for reservoir souring.
A number of key observations were made for Gullfaks. Souring development appears to follow a dual pattern of initial production of H2S, coincident with or shortly after breakthrough of injection water, followed by a subsequent decline; thereafter, sometimes several years later, a gradual increase to much higher levels is recorded. This implies that different types of souring patterns are being observed.
On the basis of improved understanding of souring development and data availability, a review of the effectiveness of mitigation techniques used in the field was undertaken. The interpretation indicates that the previously reported effect attributed to use of nitrate could also be explained by the natural progress of souring development in the field.
The work flow and methods of data interpretation opens the way to further full field evaluations as a means of improving the precision of souring simulation and assessment of mitigation methods
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.