This paper will investigate multiple production optimization case studies from the North Sea where sand management strategy contributed to increased and optimized well production, reduced integrity issues, and maintenance cost.
A new approach to sand management strategy can highly reduce, and in some cases, eliminate the needs for costly intervention operations in addition to providing uninterrupted and increased production possibilities. This paper will investigate different use of top side solids removal technology as integral part of sand management strategy and will discuss how implementing a sand management strategy that maintains solids free flow enables operators to optimize production by: Operating at maximized flow rate below ASR Optimizing well performance Reducing well down time Increasing ultimate recovery Reducing cost per barrel Extending the life of the well and protecting the wellbore and process equipment from solids buildup and long-term erosional damage: Reducing need for CT (coiled tubing) and HWO (hydraulic workover - snubbing) sand clean-out
Operating at maximized flow rate below ASR
Optimizing well performance
Reducing well down time
Increasing ultimate recovery
Reducing cost per barrel
Extending the life of the well and protecting the wellbore and process equipment from solids buildup and long-term erosional damage:
Reducing need for CT (coiled tubing) and HWO (hydraulic workover - snubbing) sand clean-out
Case studies will investigate several cases from North Sea where new approach, integrating top sides solids removal technology into sand management strategy has contributed to production increase and optimization.
Choosing a right solids management strategy and technology can increase production while reducing production cost per barrel. Using an integrated top side solids management system enables production increase from existing wells without exceeding acceptable sand rate (ASR) level and while keeping top side process integrity intact. A deliberate sand removal strategy contributes majorly to enhancing production performance of underperforming wells.
Production data, technology applications, and results will be analyzed and compared challenging existing approach to sand management. Concrete results from several case studies will be presented showing the impact a novel approach to sand management can have to production data of mature fields, including cost reduction, well optimization and integrity issues.
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.
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.
In the last years, the industry has focused on ensuring that cement is efficiently placed in the wellbore and that it does not become mechanically damaged during the life of the well. However, little work has been done on how cement mechanical integrity (CMI) relates to cement hydraulic integrity (CHI), i.e., evaluating the flow rate that could take place through the cement barrier, even if CHI is one of the ultimate objectives of cement integrity.
The analysis of hydraulic integrity requires that a CMI model is used to compute the state of stress and pore pressure in the cement and to estimate which type of mechanical failure may occur during the life of the well. It also requires that a CHI model is integrated with the CMI model to estimate the rate and amount of fluid that may flow through a cement barrier, should it mechanically fail. This provides the engineer insight into the long-term integrity of the cement plug.
This paper describes the work done on CMI/CHI models for cement plugs and presents a sensitivity analysis that demonstrates the value of an integrated CMI/CHI model. The study indicates that: 1) Well geometry, cement properties, reservoirs' pressures, cement heat of hydration, and fluids' properties are required inputs for proper analysis; 2) The changes of stresses and pore pressure over time need to be computed along the length of the cement plug, with sensitivity analysis to take the existing uncertainties into account; 3) A cement plug may preserve its sealing capability, even if the CMI model shows the existence of a micro-annulus, for example, when the fluid viscosity is very high; 4) A cement plug may lose its sealing capacity, even if the CMI model shows no induced defect, for example when a micro- annulus is propagated as a hydraulic fracture.
These last two observations are of significant importance because they show that what a CMI model cannot predict, a CHI model can.
Sleipner Vest is a large gas-condensate field which is produced by pressure depletion. Currently (January 2018) the best production well is B-1. B-1 is placed in a segment with very strong pressure support from aquifer. In summer 2016, it was about to water out. A straddle operation was planned and executed.
The straddle operation was very successful. More than a year later, B-1 still produced more than twice as much as any other Sleipner well. However, the water is eventually expected to come back in the remaining perforations. Concepts for crossflowing the gas and water production from the well into another reservoir has been investigated.
Plug and abandonment (P&A) of subsea wells is very costly and usually requires semi-submersible drilling rigs (SSR). To reduce total costs of the subsea P&A campaigns, it is beneficial to perform P&A operations with riserless light well intervention (RLWI) vessels instead of rigs. Currently, a drilling rig is required for performing P&A operations in the reservoir section and overburden, whereas intervention vessels can be used for preparatory work and wellhead removal.
This paper discusses how it can be technologically feasible to perform full P&A of subsea wells with RLWI vessels. It is shown that, for wells of simple and medium complexity, innovate approaches with use of existing technologies can enable full P&A of the entire well with RLWI vessels. This is demonstrated by thorough analyses of operational procedures using available technologies, where RLWI operations are compared to rig operations for different well scenarios. Furthermore, to quantify the cost benefits of the innovative approaches, a cost-optimization tool has been used to estimate the resulting cost and time durations of the different approaches and scenarios.
The Barents Sea offers unique drilling challenges related to issues such as biogenetic gas in shallow formations, thermogenic gas seeps up to the seabed from underlying formations, shallow formations with abnormal pressure, shallow reservoirs, low-fracture-pressure formations in part of the overburden, and naturally fractured/karstified carbonate reservoirs. This paper discusses cementing challenges when drilling wells in the Barents Sea and the experience gained using managed pressure cementing (MPC) practices.
When drilling the surface hole in potentially slightly overpressured formations, the riserless mud recovery (RMR) technique was used. For the first time on the Norwegian Continental Shelf (NCS), MPC was used when cementing the surface casing. RMR compensates for drilling the overpressurized zones without a riser and blowout preventer (BOP), and MPC allows for pressurization and monitoring of the pressure on the subsea wellhead toward the formation during the cement curing stage.
Once the marine riser and BOP were installed, controlled mud level (CML) technology was used during drilling, running casing/liners, cementing operations, and other activities. CML enables manipulation of the fluid level in the riser and therefore helps optimize downhole pressure to avoid losses and maintain an overbalance. CML has proven to be particularly useful during cementing of liners in naturally fractured reservoirs and during setting of balanced cement plugs in an open hole. As a result, high circulation rates can be achieved and conventional high-density cement slurries can be used.
MPC using either RMR or CML was employed for the first time in the Barents Sea. Examples of how cementing operations were planned and executed are described and results are presented.
Antonsen, Frank (Statoil) | De Oliveira, Maria Emilia Teixeira (Statoil) | Hermanrud, Kristine (Statoil) | Luna, Carlos Aizprua (Statoil) | Petersen, Steen Agerlin (Statoil) | Metcalfe, Richard William (Statoil) | Constable, Monica Vik (Statoil) | Alme, Arvid (Statoil) | Vee, Torill (Statoil) | Salim, Diogo (Schlumberger) | Denichou, Jean-Michel (Schlumberger) | Seydoux, Jean (Schlumberger) | Omeragic, Dzevat (Schlumberger) | Thiel, Michael (Schlumberger) | Etchebes, Marie (Schlumberger)
The Byrding asset on the Norwegian Continental Shelf (NCS) successfully drilled a two-branched horizontal producer in a structuraly complex area with many faults, changes in reservoir properties laterally, and an uncertainty on oil-water contact (OWC) levels along the trajectories. The key inputs for optimal well placement of the two branches were measurements to map the reservoir top while drilling and the OWC up to approximately 20 - 30m TVD from the wellbore.
Before deploying the ultra-deep directional resistivity tool, it was critical before drilling to evaluate how top reservoir and OWC would be mapped by inversion of electromagnetic measurements. The reservoir conditions were challenging with a low resistivity contrast towards reservoir top and a gradually changing resistivity towards the OWC. It was, therefore, critical in the pre-job phase to help all involved in the future geosteering operation to get familiar with using the ultra-deep resistivity real-time interpretation to meet the objectives and to update the geomodel after drilling.
To plan the well placement job a new workflow was applied to build a realistic geomodel based on geological understanding, legacy offset wells measurements, and seismic interpretations. Then potential scenarios generated from this geomodel were used to simulate synthetic ultra-deep directional resistivity responses and inversions results, synthetic standard LWD-data, and seismic. Finally, an updated geomodel was built after the drilling campaign, validated through "Model-Compare-Update" traditional iterative process using synthetic and real data.
In conclusion, the pre-job analysis was important to understand how to interpret reservoir top and OWC. This knowledge was used in real-time while drilling and post-operation to update reservoir top interpretation and the OWC position. This case study describes the importance of having a workflow to build a realistic high resolution geomodel that is validated with all the subsurface measurements at different scales. Deployment of such highly integrated workflow open new horizon for the collaboration between service company and operator for improved pre-job planning, real-time decisions and post-job integrated interpretation. Furthermore, integrated interpretation of data from the two wells with seismic performed over the post drilling analysis is proven to be essential to ensure future production steering of the two-branched horizontal producers.
An alternative ultra-deep azimuthal resistivity inversion algorithm was successfully used while drilling along with the standard inversion to better interpret reservoir top in the context of low resistivity contrast from this case study. An important, and unprecedented effort of pre-job planning was conducted to select optimal LWD real time dataset required. IT and "cross-platform-data-exchange" challenges were overcome to allow an extensive and innovative use of realistic geomodel scenarii for multiple measurements simulation, including from synthetic ultra-deep resistivity inversions results, standard LWD-data, to seismic interpretation.
This paper discusses installation of the longest high-performance (HP) and rotating 11-3/4" expandable liner on the Elgin field in the Central-North Sea sector of the UK that enabled isolating weak layers in the overburden formations on EIE well, providing sufficient mud weight window to permit drilling high pressure and gas bearing zones. The planning and execution of this record presented challenges beyond those encountered in standard well conditions due to narrow mud weight window (NMWW) and critical requirement of zonal isolation.
EIE well was the third of the 2015-2017 infill campaign on Elgin field. The well faced major challenges in the 12-1/2" section due to the NMWW which triggered the deployment of the contingent well architecture with HP 11-3/4" expandable liner. This critical requirement of zonal isolation significantly impacted the preparation and risk assessment of expandable liner operations. A new expansion assembly design was implemented to allow rotation of the 11-3/4" size system to improve the cement job quality. Moreover, all contingency procedures were significantly modified to ensure that the objective of the specific well constraints were considered.
After under-reaming while drilling 12-1/4" × 14" section down to planned depth, 860m of 11-3/4" liner was run with no open hole problems. This liner was successfully rotated at bottom prior to pumping cement and fully expanded without incident. The system was successfully pressure tested prior to drill-out of the plugs and the shoe assembly was drilled with no issues.
Running of an 860m HP 11-3/4" expandable liner and rotating shoe assembly on EIE well is a record (longest HP string run before was 360m) and considered as a remarkable achievement. However, liner objectives were not fully met and cement squeeze below the shoe had to be performed. Post-job investigation highlighted issues related to dart selection and related cement over-displacement, limited contingences in case of expansion pressure loss, and the ability to pull the liner to surface in a NMWW. These issues remain to be solved for optimisation of future deployments.
This paper provides information on the design and operational aspects that should be considered for expandable liner operations on complex wells with NMWW. Understanding advantages and limitations of the system will open up opportunities to improve the technology and help to reduce operational risk.