Hydrodynamic aquifer conditions have been described in many basins around the world since first introduced by Hubbert1 in 1953. The hydrodynamic aquifer concept in Ormen Lange has been assessed using iso-potential mapping1 and dynamic simulation of the fluid fill development (i.e. imbibition) over geological time. Simulation shows2,3 the hydro-dynamically tilted/stepping contacts depend on rate of water flow across the aquifer, stratigraphic baffling and faulting, effective aquifer area and reservoir quality (NTG and effective permeability). The role of sealing faults over geological time scale is downplayed in terms of justifying the fluid distribution. Baffling during production is, however, expected. In Ormen Lange the hydrodynamic aquifer has pushed the gas from the crest of the structure into the south of the field leaving behind a northward-thickening prism of residual gas which is imaged by a seismic DHI. Confirmation of the hydrodynamic aquifer scenario in this field was achieved after drilling an appraisal well in the north of the structure that corroborated fluids (water with residual gas) and pressures as prognosed by the hydrodynamic aquifer model.
Ormen Lange is the second-largest gas field in Norway, currently providing 20% of the domestic gas consumption for the UK. As one of the world's largest subsea big-bore gas wells - with production rates up to 350 MMscf/d per well, a 120-km tieback to shore, subzero seabed temperatures and a design life of more than 30 years - these wells provide unique technical challenges. Due to the low reservoir rock strength, high velocities and the life expectancy of these wells, sand control was identified as a prerequisite from day one.
This paper clarifies the logic of the selected sand control method and describes the extensive testing required to qualify the sand control hardware and associated completion fluids for the expected operating conditions. The execution of thirteen successful sand control completion installations will be discussed, including both ends of the success spectrum, and well performance will be covered.
Throughout the four-year installation campaign to date, a number of new technologies were qualified and successfully integrated into the lower completions. These included cableless gauges to provide data closer from the reservoir inflow area, tagged proppant for individual subsea well fingerprinting if proppant is found at the gas plant, and water-tracer technology to aid in identifying the subsea source of potential formation water breakthrough.
This subject explains the extent of the effort to progress an ambitious field development based on big-bore gas wells only (to reduce well count) from the drawing board to flawless execution and world-class production. Relevance also relates to other major big-bore, high-rate gas subsea developments with sand control requirements that are currently being pursued in similar harsh environments (deep water, Arctic conditions, sub-zero seabed) that might have interest in the application of Ormen Lange's successfully implemented technology.
Delivering wells capable of high rate and high ultimate recovery heavy oil is one of the key requirements for success of the Ultra-deepwater Parque das Conchas development in block BC-10, Campos Basin, Brazil.
This paper presents the Parque das Conchas well design to achieve these objectives while tackling key challenges such as shallow reservoir setting below mud line and low fracture gradient setting. It explains fabrication and final preparation efforts followed by a detailed description of execution efforts on the Transocean mobile drilling unit Arctic-1, including performance and learnings by well section.
The Parque das Conchas well design and execution efforts have resulted in several significant results to date:
• Two of the longest horizontal open hole wells successfully drilled and completed with a full-length alpha and alpha/beta wave gravel pack in Brazil at 1,115 and 1,160m.
• Top quartile drilling and completion times.
• Use of the Transocean Arctic-1 with a surface BOP (SBOP) system (Ref 1).
• Promising well performance from initial production.
For the drilling and completion of the Parque das Conchas wells a combination of existing and new technologies have been used. New technologies include the SBOP system, Spacer Spool, Collapsible 9-5/8" Casing Shoe Joint, 4-1/4" washpipe, tailpipe swell element and premium sand control screens with extensive mesh size QA/QC. Existing technologies are point the bit rotary steerable, Production Screen Tested (PST) drilling fluid, Alpha Wave Gravel Packing, Delayed Filtercake Breakdown system and Fluid Loss Valve (FLV) lower completion isolation.
Well construction results have been excellent to date with the wells delivered on time, within budget and with productivity indices exceeding expectations. Credit goes to a team of people working closely together across disciplines in wells, subsurface, subsea, production operations, HSE, logistics, finance and QA/QC departments, across a global team.
Nishikiori, Nobuo (Norske Shell A/S) | Sugai, Keiichiro (Arabian Oil Co. Ltd.) | Normann, Clas (Talisman Energy Norge AS) | Onstein, Arne (Talisman Energy Norge AS) | Melberg, Oddbjoern (DONG Norway) | Eilertsen, Terje (DONG Norway)
This study describes an improved engineering workflow to perform technical evaluation and screening of gas injection EOR. A successful case study demonstrates how field data, engineering analysis and simulation are integrated to precisely model gas injection EOR. This workflow can be adaptable for any type of reservoir and can be utilized as a fast-track screening workflow for gas injection EOR.
The target for this study was the Gyda reservoir located in the southern part of Norwegian North Sea in the Norwegian Continental Shelf. The reservoir is of heavily faulted heterogeneous shallow marine sandstone. As the measure of heterogeneity, a Dykstra-Parson's coefficient1 (VDP) of more than 0.8 has been measured from core plug data.
For the purpose of building a tool that can be utilized for gas injection EOR study, a five-step workflow has been implemented:
The results of this case study confirmed the capability of the described workflow to model gas injection EOR for the heterogeneous sandstone reservoir. Potential gas channeling in high permeability streaks and an improved displacement by gas was precisely modeled by the workflow. Injection strategies, such as WAG, SWAG and gas injection have been screened by the model, leading to a conclusion in relatively short period of time.
In the search new for oil and gas fields great water depth is explored. One of these areas with large water depth is the south Norwegian Sea where the water depths exceeds 1000 meter. One identified drilling challenge in such areas is the deep water combined with soft overburden sediments. To ensure correct penetration of the reservoir rotary steerable systems will be used to drill deviated well paths. However, the behavior of rotary steerable systems in soft formation was a concern because building angle in weak formations gives less steering response from the wellbore sidewall which limits the maximum dog leg generation.
A method for calculating the rotary steerable systems steering response in different formations was developed by correlating the rotary steerable systems maximum response setting to the rock strength. This correlation was used to give guidelines to determine which sections were most likely to give good response when building angle.
The sedimentary rock strength analysis indicated low values in the ranges of 2-8 MPa which call for careful directional planning. Attention with respect to the planning of the wellpaths maximum dog leg severity had to be integrated with the rock strength profile. The maximum dog leg severity obtainable in the overburden was estimated to be 2° to 2.5°.
The first deviated wells from the field have given the anticipated steering response. This method should be applicable for other areas planning deviated wells in deep water with soft overburden.
Directional wells are often the preferred solution when developing offshore fields. Especially since offshore wells have to be drilled from the same template below the (future) production platform or sub-sea production unit. It is critical to place wells correctly to reach reservoir targets and to obtain the desired reservoir section length. When the reservoir targets tolerances gets tighter it is even more important that the actual well path follows the planned well path. In addition to follow the planned well path, the uncertainty in the geological prognosis makes it sometimes necessary to adjust the well path real time based on geological information collected while drilling, referred to as geosteering.
Rotary steerable systems (RSS) are one of the various technologies in use to change well directions, and RSS are widely used today. Some of the available RSS use pads or stabilizers in contact with the formation to create directional change at the bit face. The directional change is controlled by directing the mudflow through the tool. The effect is controlled by the amount of controlled flow given in %, typically in steps on 20%, defined as % active steering. Since, the systems rely on contact with the borehole wall to get directional control hole stability problems such as washouts, key seats and breakouts can negatively impact the directional performance on these systems (Schaaf et al. 2000). Drilling experience with RSS in directional wells has also shown that some geological formations give less response to directional change. Therefore different formations need more active steering to obtain the same directional change. The level of resistance a formation shows when direction changes are attempted by using a RSS is defined as directional response steerability (steerability). Formations with high steerability will enable rapid directional changes. While less steerable formations gives less directional change. Directional change itself is reported as dog leg severity (DLS), defined as the directional change (in degrees) per 30 meter or 100 feet. To predict formation steerability, already drilled directional wells can be used to back calculate an average formation stiffness factor. However this method requires that there are existing directional wells in the area. This is often not the case when the main production drilling program is planned for a new field and the only wells that have been drilled are vertical exploration wells.
Vickers, Stephen R. (Baker Hughes Drilling Fluids) | Hutton, Alistair Paul (Baker Hughes Drilling Fluids) | Lund, Arne (Baker Hughes Drilling Fluids) | McKay, Ian Donald (Cleansorb Ltd.) | Van Kranenburg, Aart (Shell) | Twycross, Jean (Norske Shell A/S)
The challenges in developing the Ormen Lange field were the harsh weather conditions, deep-water depth, subsea topography and sub-zero seabed temperatures. Due to environmental constraints and the selected sand face completion type, a water-based fluid system was required. This paper discusses the design of the fluids to give full hydrate inhibition, maximize breaker effectiveness, provide low overbalance, and reduce corrosion risk. An extensive research and development program was initiated that spanned over two years. The study included bridging and chemical component selection, brine evaluation, hydrate suppression measurement, elastomers compatibility, extensive breaker treatment studies, formation damage measurements using actual reservoir core and long term corrosion testing. An in-situ generating acid/enzyme breaker treatment deployed in the gravel pack carrier fluid was developed to optimise filtercake cleanup whilst providing a non-corrosive environment for the selected gravel pack screens and lower completion metallurgy. The basis of design and knowledge gained in the laboratory testing phase was transferred to the field and the first three wells of the initial development phase have been drilled and completed trouble-free. The resulting production rates have met expected targets proving low formation damage and an efficient cleanup was achieved.
When the Ormen Lange field comes into full production, it will make Norway the second largest exporter of natural gas in the world and will supply 20% of the UK's gas requirement. Maximum daily exports from the Ormen Lange field will amount to 80 MSm3/day of gas and 50,000 bbls of condensate. The gas will be piped to the UK through the Langeled Pipeline which is the world's longest underwater gas pipeline at 1200 km long. The field was discovered in 1997 and is the second largest gas field on the Norwegian continental shelf. It is situated 140 km west of Kristiansund in the Norwegian Sea in deepwater, with depths up to 1100 meters and seabed temperatures as low as minus 1°C. The field has proven gas reserves of 400 billion m3 (14 Tcf), with an expected field life of 25-30 years. The first phase of the field development consists of two subsea templates with eight subsea big bore wells requiring a total investment close to 10 billion USD. During the later phases of the project, a third and possible fourth template will be installed bringing the total number of wells up to 24.
Each of the big bore wells is designed for production rates up to 10 MSm3/day (350 MMScf/day). Therefore optimum drilling and completion fluid selection was considered to be a key focus area to maximise the open area to flow and associated well productivity, in order to comply with the planned lifetime and production targets.
4D-seismic interpretation plays a key role in the reservoir management of the Draugen field, situated offshore Norway. High-quality time-lapse seismic surveys conducted in 1990, 1998, 2001, and 2004 have all shown sharp resolution for the areal and vertical definition of the water movement toward the producing wells.
Excellent reservoir properties with relatively few high-rate wells and an expected recovery factor exceeding 60% make Draugen one of the best performing fields offshore Norway. The field has a simple geology; however, the reservoir structure is relatively uncertain because of the low number of well penetrations for calibrating the structure. Fortunately, the 4D-seismic interpretations have largely compensated for this shortcoming by providing improved lateral control for refining the reservoir-simulation models.
All of the 4D interpretations conducted so far have indicated the need for simulation-model changes such as modified reservoir volumes in certain areas, revised fault transmissibilities, and improved relative permeability characteristics. Integration of the 4D-interpretation results has greatly improved the various Draugen reservoir-simulation models, enabling improved forecast and reserves estimates as well as better business decisions. Effects on field reservoir management have included revising the water-injection strategy, converting a producer to an injector, repositioning a development well, and drilling an appraisal well.
The Draugen field is located 100 km offshore Norway. The field has excellent reservoir characteristics that have enabled a field development with a minimal number of appraisal and development wells given the areal size of the field. The lack of well control for the structural mapping has resulted in a relatively high degree of uncertainty for both the top reservoir structure and the in-place volume.
Therefore, interpretation of the field structure is largely dependent upon 3D-seismic surveys conducted in 1990, 1998, 2001, and 2004 and the associated seismic time-to-depth conversion work. The latter three surveys included 4D-seismic interpretations of the water encroachment into the reservoir; the most recent survey was acquired as a combined high-resolution and 4D survey.
Reservoir management for Draugen uses a full-field reservoir-simulation model (FFM) based on a geological model with numerous faults. Replicating the dynamic communication across several non-neighbor connections (NNCs) with hundreds of on-lap connections between the different reservoirs in the simulation model poses significant challenges.
4D-seismic interpretation of the water influx is important for establishing fault communication and modifying the geological model for a viable history match. Iterations of geologic modeling, reservoir simulation, and seismic forward modeling are generally recommended for consistency between the dynamic model and 4D seismic in accordance with current "best-practice?? methodology (Lumley and Behrens 1998; Pagano et al. 2000).
This paper covers the HPHT Gas-Condensate Exploration Well, 6406/9-1 on the Onyx SW prospect of the Norway Sea in the late spring of 2005 (Figure 1 and 2). The well test design and execution is presented in the paper, including; up front planning, job design, technology selection and review of the test results vs. the objectives for the well test. The paper also addresses how health, safety and environmental considerations were handled.
Traditional well testing methods and equipment have evolved over the years, adapting to changing requirements. This has resulted in requirements for more complex data gathering over a shorter time with much stricter environmental and safety constraints. Coupled with increased needs for more accurate reservoir data for prospect evaluation, this has put a higher emphasis on upfront planning and improved technical performance together with extensive use of advanced fluid data gathering methodologies.
This paper demonstrates how the above was addressed for the Onyx SW and how the results compared with the set goals. The application of the latest technologies in Gas-Condensate well testing was used on this job. Experiences from this were later used as the basis for other gas-condensate prospects, including those in the Russian sector of the Barents Sea.
This paper focuses in particular on Fluid Sampling, Surface Well Testing and Subsea equipment. As several service companies were involved on this particular job, we have only included some general and limited content for the other services involved.
Production from Draugen started in 1993. In its 14th year Draugen faces declining oil and increasing water production and is around halfway in its production life. The field development with water injection and relatively few wells has proved to be very successful. This paper shows how well and reservoir surveillance has been set-up in the Draugen field. Interesting features of this set-up are
The paper provides clear examples of how surveillance is supporting reservoir management and production optimisation in the field.
Nilsen, Norwegian Petroleum Directorate; and S.M. Skjaeveland, SPE, U. of Stavanger Summary A review of the tidal response in petroleum reservoirs is given. Tidal response is caused by periodic changes in overburden stress induced by the ocean tide; the "tidal efficiency factor" is derived by two different approaches and is in line with a recent well test in the Ormen Lange gas field. For small geomechanical pertubations like the tidal effect, we show that a simplified coupling of geomechanics and fluid flow is possible. The coupling is easy to implement in a standard reservoir simulator by introducing a porosity varying in phase with the tide. The observation of the tidal response in petroleum reservoirs is an independent information provider [i.e., it provides information in addition to the (average) pressure and its derivative from a well test]. The implementation of the tidal effect in a normal reservoir simulator gives us the opportunity to study complex multiphase situations and to evaluate the potential of the tidal response as a reservoir-surveillance method. The case studies presented here focus on the possibility of observing water in the near-well region of a gas well. The literature seems sparse in this area. Also, our approach of simplified coupling of geomechanics and fluid flow for small geomechanical effects, and the possibility to implement this in a normal reservoir simulator, has not (to our knowledge) been discussed in the literature. Several authors have derived a tidal efficiency factor, but a review and comparison study seems to be missing.