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Collaborating Authors
SPE Norway One Day Seminar
Real-Time Fluid Mapping Ensures Reserve Development Via Optimized High-Angle Infill Drilling
Bravo, Maria Cecilia (Schlumberger) | Baig, Mirza Hassan (Schlumberger) | Gueze, Nicolas (AkerBP) | Kotwicki, Artur (AkerBP) | Horstmann, Mathias (Schlumberger) | Blanco, Yon (Schlumberger) | Guevara, Carlos (Schlumberger) | El-Khoury, Jules (Schlumberger) | Scott, Paul (Schlumberger)
Abstract Reservoirs containing complex structures require additional technology to obtain optimum performance from planned production wells. In this scenario, logging-while-drilling (LWD) technologies play an important role in well construction from purely geometric trajectories to the real-time trajectory steering and formation and fluid characteristics measurements. A North Sea Alvheim field case study is presented in this paper. During the exploration and initial development phase of the field, the oil/water contact (OWC) varied to 7 m due to the presence of mudstone baffles and faults. The field has been on production since 2008 using bottom-aquifer drive, and current fluid contacts have shifted from their initial levels. To enhance field recoverable reserves, an infill development plan was required to place the wells within a thin oil rim between the gas/oil contact (GOC) and the OWC. Field objectives included achieving optimal well landing, identifying the moveable oil in situ, mapping the hydrocarbon-bearing reservoir, and identifying the hydrocarbon type (oil or gas) along the wellbore trajectory. To address the challenges, an integrated drilling bottomhole assembly (BHA) consisting of a deep-directional resistivity (DDR) tool to refine the reservoir delineation and structural positioning, a downhole fluid analyzer (DFA) using optical spectrometry to identify in-situ fluids, and advanced petrophysical measurements provided a complete quantitative reservoir evaluation during well construction. This paper presents the design, execution, and interpretation of the acquisition program to achieve the well objectives, including positioning the producer well in the desired moveable fluid zone. The final results demonstrated that integrating LWD measurements in the operation added significant value toward achieving the desired wellbore trajectory by optimally positioning the wellbore in the desired reservoir fluid layer.
- North America > United States (1.00)
- Europe > United Kingdom (1.00)
- Europe > Norway > North Sea > Northern North Sea (0.36)
- Europe > Norway > North Sea > Northern North Sea > South Viking Graben > Vana Basin > RL 088 BS > Block 25/4 > Alvheim Field > Lista Formation > Våle Formation (0.99)
- Europe > Norway > North Sea > Northern North Sea > South Viking Graben > Vana Basin > RL 088 BS > Block 25/4 > Alvheim Field > Lista Formation > A2 North Heimdal T60 Formation (0.99)
- Europe > Norway > North Sea > Northern North Sea > South Viking Graben > Vana Basin > RL 088 BS > Block 25/4 > Alvheim Field > Hermod Formation > Våle Formation (0.99)
- (28 more...)
Abstract Occasionally the drilling fluid pressure exceeds the fracturing pressure and drilling fluid is lost to the formation. Several types of lost circulation materials (LCM) are used to heal such losses. However, in standard testing procedures like American Petroleum Institute Recommended Practice 13-1 or 13-2, only a 100psi or 500psi differential pressure is required in the pressure cell for LCM testing. It is shown that this pressure is by far too small to give any meaningful data for LCM performance. Lost circulation can occur in all well sections. Especially, will lost circulation represent a potential problem during drilling long sections with varying formation strengths and varying formation pressures. In a typical drilling situation, the minimum static overbalance in the well is more than 100psi in order to control the formation pressures and avoid influx of formation fluids into the wellbore. During drilling this overbalance will increase due to, amongst others, frictional effects. These effects, together with variations in formation pressures sometimes lead to dynamic differential pressures exceeding 2000 or even 3000psi. Testing under conditions exceeding the expected maximum differential pressures are meaningful in order to identify the sealing capabilities of LCM materials under such conditions. Some tests focus on losses through tapered slots. In such cases particles larger than the slot outlet will sooner or later contribute to stopping the loss. In a real situation the fracture would be in position to open further. Hence, such tests are not optimal. Other tests are based on slot openings as the minimum size. In such cases the fluids will need to bridge off the opening to work. Based on bridging formation ideas, a development of new LCMs was conducted. These LCMs were able to handle downhole pressure differences. Slotted disks were installed into a high-pressure cell. The slots were 18.00 mm long and 400, 700, 1600, 2000 and 2500μm wide which were made into disks with a diameter of 24.13 mm. Drilling fluid was pumped through the cell and an LCM filter cake was formed across the disk slot. The pressure required to break this filter cake was obtained (unless it exceeds 5000 psi) and recorded. The fluid filtration losses through the apparatus was strongly dependent on the LCM concentration. A set of LCM tests was performed, and examples are given where the LCM actually would withstand a differential pressure 5000 psi across the slotted disks without failing.
- Europe (1.00)
- Asia (0.68)
- North America > United States > Texas (0.28)
Nine Years Operational Experience of the Vega Field – Design, Experience, and Lessons Learned
Hatscher, Stephan (Wintershall Norge AS) | Kiselnikov, Maxim (Wintershall Norge AS) | Ugueto, Luis (Wintershall Norge AS) | Norheim, Bård (Wintershall Norge AS) | Olsen, Viggo (Wintershall Norge AS) | Malmanger, Eva (Wintershall Norge AS) | Alvestad, Atle (Wintershall Norge AS)
Abstract The Vega field is a gas condensate / volatile oil asset located in the Northern part of the North Sea. It comprises three subsea templates, daisy-chained on a 52 km long subsea multiphase flowline to the Gjøa host platform. The high temperature, high pressure field was developed by Norsk Hydro and Statoil and came onstream in 2010; it came under operatorship of Wintershall in 2015. A lot of operational experience was gained within those years. The paper will reflect on the assumptions that led to the design of the asset and juxtapose this with the findings after first oil. Within this, especially the subject of paraffin precipitation will be highlighted. This was perceived as the highest risk to the asset upon development. Later field life, however, showed no indication of wax precipitation at all. Furthermore, and especially since the takeover by Wintershall, production optimization and prolonging field life has been a strong focus. The paper will showcase several aspects of this, like re-vitalizing wells through acid stimulations, extending lifetime with an infill well campaign, a new spare part strategy, or chemical optimization on the continuous hydrate inhibition cocktail. Moreover, it will also display further activities to extend lifetime even more by changes in the hydrate philosophy. The story shows that with fresh eyes and new approaches, also smaller fields can be optimized efficiently, leading to increased lifetimes and improved economics.
- Europe > Norway > North Sea > Northern North Sea (1.00)
- North America > United States > Colorado > Mesa County (0.72)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.47)
- Europe > Norway > North Sea > Northern North Sea > North Viking Graben > PL 190 > Brent Group > Tarbert Formation (0.99)
- Europe > Norway > North Sea > Northern North Sea > North Viking Graben > Block 35/8 > Vega Field > Tarbert Formation (0.99)
- Europe > Norway > North Sea > Northern North Sea > North Viking Graben > Block 35/8 > Vega Field > Ness Formation (0.99)
- (46 more...)
Abstract A fit for purpose 4D Geomechanical model is regarded valuable for most fields. Although tools for building such models have been available for some time they are commonly not made or not fully utilized due to the extensive amount of time, complexity and costs involved. In Equinor a workflow (DE4RM) has been developed for fast 4D geomechanical modeling, effective visualization and interpretation. Using this workflow, models have been built for more than 20 fields over the last 4 years and results applied for a variety of areas including input to seismic time shift analysis, short and long term well planning, estimation of cooling effects from injectors, subsidence/compaction predictions, input to well completion, monitoring optimization, overburden integrity studies, out of zone injection and fault re-activation assessment. Some examples on such use will be given in this paper. On the modeling side key factors for efficient modeling are utilization of existing reservoir models, use of commercial finite element software and a streamlined, easy to use, workflow for all pre-processing steps. Particularly, a well-equipped toolbox for various grid-editing functionality has been essential for being able to complete the modeling fast enough (1-3 weeks). Once a model is built it is readily available for both geomechanical experts and non-specialists through the open source powerful visualization platform Resinsight. In this software geomechanical capabilities have been developed over the last years guided by practical use of the models. Further development on both the modeling, visualization and post-processing side is ongoing and as Resinsight is open source, use of the software and development of new functionality is possible for anyone. In summary, 4D geomechanical modeling and utilization of such models has become a daily activity in Equinor for numerous applications, gradually replacing simplified 1-D based methods with the faster and more accurate DE4RM methodology.
- Europe > Norway > Norwegian Sea (0.46)
- Europe > Norway > North Sea > Northern North Sea (0.28)
- Europe > United Kingdom > North Sea > Central North Sea > Central Graben > Block 22/30b > Shearwater Field > Fulmar Formation (0.99)
- Europe > Norway > Norwegian Sea > Halten Terrace > PL 199 > Block 6506/11 > Kristin Field > Tofte Formation (0.99)
- Europe > Norway > Norwegian Sea > Halten Terrace > PL 199 > Block 6506/11 > Kristin Field > Ile Formation (0.99)
- (48 more...)
Abstract Vestflanken 2 (VF2) is an ongoing field development project in the Oseberg area. The development concept chosen includes an unmanned wellhead platform (Oseberg H) with seven gas lifted production wells, two gas injection wells in addition to two sub-sea production wells using existing infrastructure. Four of the production wells will be multi-laterals completed with autonomous inflow control devices (AICDs). AICDs in VF2 wells have two main objectives: Accelerate oil production by delaying gas breakthrough Choke back gas after gas breakthrough AICDs have been successfully implemented at the Troll field, and further implementation on other fields are pursued. There are differences between fields and careful considerations must be taken when implementing the technology on a new field development like VF2. It is essential to select a type and size of the AICD that fit the application. This paper discusses the process of selecting the AICD flow capacity. The lower completion design was based on experiences and results from inflow simulations. However, the design for future wells will be made based on production experience from the first VF2 wells in production. This paper also discusses the clean-up and start-up of the first VF2 well and presentation of results. The well is well instrumented with downhole P/T gauge and multi phase flow meter on well head. This is the operators first AICD well equipped with multi phase meter which makes it a very good candidate for evaluating flow performance and AICD efficiency. The well was started October 2018. Step-rate tests were performed on both branches and on the comingled MLT production. This allowed to compare measured data from the multi-phase meter to results obtained by the simulation model. The simulation results matched the measured data to a varying degree with different model assumptions. The initial well performance data and simulation model will be valuable tools when evaluating AICD design for future wells.
- South America > Brazil > Rio de Janeiro > South Atlantic Ocean > Campos Basin > Block BM-C-7 > Peregrino Heavy Field (0.99)
- South America > Brazil > Rio de Janeiro > South Atlantic Ocean > Campos Basin > Block BM-C-47 > Peregrino Heavy Field (0.99)
- Europe > Norway > North Sea > Northern North Sea > South Viking Graben > Vana Basin > RL 088 BS > Block 25/4 > Alvheim Field > Lista Formation > Våle Formation (0.99)
- (50 more...)
Successful Implementation of Real-Time Look-Ahead Resistivity Measurements in the North Sea
Khalil, Haitham (Schlumberger) | Seydoux, Jean (Schlumberger) | Denichou, Jeanmi (Schlumberger) | Omeragic, Dzevat (Schlumberger) | Salim, Diogo (Schlumberger) | Thiel, Michael (Schlumberger) | Beeh, Hany (Schlumberger) | Dhaher, Karam (Schlumberger) | Constable, Monica Vik (Statoil) | Antonsen, Frank (Statoil) | Tiku, Arun (Statoil) | Hodne, Jarleif (Statoil) | Lokna, Joakim (Statoil) | Haldorsen, Kjetil (Statoil) | Aarflot, Haakon (Statoil) | Fjellanger, Jan Petter (Statoil)
Abstract In this case study, we present the use of a new look-ahead resistivity technology to solve a challenge on the Valemon field where the top of the reservoir could not be mapped from surface seismic. The objective was to extend the overburden section deep enough to secure sufficient formation strength at the casing shoe while eliminating the risk of accidental drilling into the reservoir below. The application of the new technology secured standard casing design, and eliminated the extra time and costs associated with implementation of the managed pressure drilling technique. The target was to extend the 12 ¼-in overburden section 10-15m TVD into the Viking Group, as this formation generally provides sufficient formation strength for the 9 7/8-in casing shoe to enable conventional drilling of the following reservoir section. As there was a risk that the Viking Group could be absent or very thin in this area of the Valemon field, the look ahead measurement was used to monitor the formations ahead of the bit while drilling. Detection of higher resistivity ahead of the bit indicating an approaching reservoir would enable stopping prior to drilling into it. No reservoir response was detected ahead of the bit, and this enabled a safe extension of the 12 ¼-in section into the Viking Group as per the objective.
- Geophysics > Seismic Surveying (1.00)
- Geophysics > Borehole Geophysics (0.95)
- Europe > Norway > North Sea > Northern North Sea > East Shetland Basin > PL 50 > Block 34/11 > Valemon Field > Cook Formation (0.99)
- Europe > Norway > North Sea > Northern North Sea > East Shetland Basin > PL 50 > Block 34/11 > Valemon Field > Brent Group (0.99)
- Europe > Norway > North Sea > Northern North Sea > East Shetland Basin > PL 50 > Block 34/10 > Valemon Field > Cook Formation (0.99)
- (32 more...)
Abstract An oil field can be classified as mature when its production rate is significantly declining and/or when it is close to reaching its economic limit. A field might also be considered mature when it is close to attaining a recovery factor considered acceptable for its reservoir mechanisms. Strategies and methodologies to rejuvenate the field, enhancing production and increasing longevity of life will then commence. One of the most common methods of enhancing oil recovery (EOR) is by means of waterflooding, a device whereby injector wells are drilled in an oil field to inject water or gas into the reservoir to increase pressure and stimulate production. This, however, is a complex process posing its own uncertainty in optimally delivering increased production due to the complexity of reservoir type and well design. Having the ability to listen behind casing and deducing flow allocation of injection in which to increase the sweep and improving reservoir production performance becomes vital to enhancing oil recovery. This paper demonstrates how spectral noise logging has aided in rejuvenating oil fields and enhancing oil recovery. Three different oil field examples are examined and discussed, illustrating the methodology and benefits of better understanding flow allocation behind casing to provide much-needed solutions to aid in field life longevity.
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Open hole/cased hole log analysis (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Production logging (1.00)
Abstract While drilling horizontal sections, an operator experienced tool-joint wear, which in extreme cases was one-sided, necessitating the replacement of many drill-pipes to minimize the risk of drill-string failure. Since there were no observable signs of the wearing process, the strategy has been to trip midway through the section to inspect the pipes. With the goal to drill the section in one run, an investigation of the root causes of the abnormal wear has been started. To check whether some hidden signal patterns could help detecting under which circumstances the tool-joints were worn out, a play back of some of those drilling operations has been undertaken with specific attention to whether transient hydraulic and mechanical models could help differentiate abnormal measurement signatures. In parallel, it has been investigated with computational fluid dynamic (CFD) software whether synchronous whirl of tool-joints would generate a specific pressure signature that could easily be recognized. As the asymmetrical wear of the tool-joints indicated the presence of synchronous whirl, it has also been analyzed how side forces were distributed along the drill-string. Neither the playback nor the CFD analyses pointed to conditions leading to tool-joint wear. On the other hand, the side force analysis showed that because of extensive directional work linked to geosteering, reaction forces on the tool-joints were very unevenly distributed on the first 500m of drill-string behind the BHA. However, the distribution of the positions of the high and low side forces changed radically for different bit positions. Numerous hard-stringers were encountered while drilling which suggests that the irregular distributions of side-forces on the string have been maintained for longer periods of time. As a result, these conditions have allowed drill-string whirl to be kept sufficiently steady with the consequence of severely damaging the tool-joints. Mathematical modelling of the drill-string behavior can help determining the critical rotational speed as a function of the weight on bit by which whirl can take place. With this information at hand, it is then possible to give concrete advice to the drilling team on which drilling parameters to use to minimize the risk of tool-joint wear.
- Europe > Norway (0.68)
- Europe > United Kingdom > England (0.28)
- Europe > Norway > Norwegian Sea > Halten Terrace > PL 475 BS > Block 6507/10 > Maria Field > Tilje Formation (0.99)
- Europe > Norway > Norwegian Sea > Halten Terrace > PL 475 BS > Block 6507/10 > Maria Field > Garn Formation (0.99)
- Europe > Norway > Norwegian Sea > Halten Terrace > PL 475 BS > Block 6407/1 > Maria Field > Tilje Formation (0.99)
- (4 more...)
- Well Drilling > Drillstring Design (1.00)
- Well Drilling > Drilling Operations > Directional drilling (1.00)
Abstract In this work we present a systematic geosteering workflow that automatically integrates a priori information and the real-time measurements for updating of geomodel with uncertainties, and uses the latest model predictions in a Decision Support System (DSS). The DSS supports geosteering decisions by evaluating production potential versus drilling and completion risks. In our workflow, the uncertainty in the geological interpretation around the well is represented via multiple realizations of the geology. The realizations are updated using EnKF (Ensemble Kalman Filter) in real-time when new LWD measurements become available, providing a modified prediction of the geology ahead of the bit. For every geosteering decision, the most recent representation of the geological uncertainty is used as input for the DSS. It suggests steering correction or stopping, considering complete well trajectories ahead-of-the-bit against the always updated representation of key uncertainties. The optimized well trajectories and the uncertainties are presented to the users of the DSS via a GUI. This interface enables interactive adjustment of decision criteria and constraints, which are applied in a matter of seconds using advanced dynamic programming algorithms yielding consistently updated decision suggestions. To illustrate the benefits of the DSS, we consider synthetic cases for which we demonstrate the model updating and the decision recommendations. The DSS is particularly advantageous for unbiased high-quality decision making when navigating in complex reservoirs with several potential targets and significant interpretation uncertainty. The initial results demonstrate statistically optimal landing and navigating of the well in such a complex reservoir. Furthermore, the capability to adjust and re-weight the objectives provides the geosteering team with the ability to change the selected trade-offs between the objectives as they drill. Under challenging conditions, model-based results as input to a decision process that is traditionally much based on human intuition and judgement is expected to yield superior decisions. The novel DSS offers a new paradigm for geosteering where the geosteering experts control the input to the DSS by choosing decision criteria. At the same time, the DSS identifies the optimal decisions through multi-objective optimization under uncertainty. It bridges the gap between developments in formation evaluation and reservoir mapping on one side, and automation of the drilling process on the other. Hence, the approach creates value based on the existing instrumentation and technology.
- Geophysics > Borehole Geophysics (1.00)
- Geophysics > Seismic Surveying > Seismic Processing (0.34)
- Europe > Norway > Norwegian Sea > Halten Terrace > PL 128 > Block 6608/10 > Norne Field > Tofte Formation (0.98)
- Europe > Norway > Norwegian Sea > Halten Terrace > PL 128 > Block 6608/10 > Norne Field > Not Formation (0.98)
- Europe > Norway > Norwegian Sea > Halten Terrace > PL 128 > Block 6608/10 > Norne Field > Ile Formation (0.98)
- (3 more...)
Abstract Objective of the paper is to describe and present results of using a "Digital Twin" in Drilling Operations (Planning and Engineering, Training and Operational Support) in the last 10 years for Operators worldwide. The concept of Digital Twin was first introduced by Michael Grieves at the University of Michigan in 2003 through Grieves’ Executive Course on Product Lifecycle Management. Winning a Formula 1 race is no longer just about building the fastest car, hiring the bravest driver and praying for luck. These days, when a McLaren technology group races in Monaco or Singapore, it beams data from hundreds of sensors wired in the car to Woking, England. There, analysts study that data and use complex computer models to relay optimal race strategies back to the driver. The McLaren race crew and the online retailers both harness data and use algorithms to make reasonable projections about the future, Parris explains. The concept is called Digital Twin [1]. A Digital Twin contains information such as a piece of equipment or asset, including its physical description, instrumentation, data and history. A Digital Twin can be created for assets ranging from a well to a piece of equipment to an entire oilfield. For example, a subsea system could have a Digital Twin via a simulation model of a subsea system's components, including the blowout preventer, tiebacks, risers, manifolds, umbilical and moorings. Drilling and extracting simulations can determine whether virtual designs can actually be built using the machines available," GE said. "Last but not least, real-time data feeds from sensors in a physical operating asset are now used to know the exact state and condition of an operating-asset product, no matter where it is in the world"[2].
- Europe > Norway > North Sea (0.28)
- Asia > Middle East > UAE (0.28)
- North America > United States > Michigan (0.24)
- Europe > United Kingdom > England (0.24)
- Europe > Norway > North Sea > Northern North Sea > North Viking Graben > PL 043 > Block 30/7 > Martin Linge Field > Tarbert Formation (0.99)
- Europe > Norway > North Sea > Northern North Sea > North Viking Graben > PL 043 > Block 30/7 > Martin Linge Field > Ness Formation (0.99)
- Europe > Norway > North Sea > Northern North Sea > North Viking Graben > PL 043 > Block 30/7 > Martin Linge Field > Lunde Formation (0.99)
- (33 more...)