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.
Acquisition of marine seismic data in shallow water with towed cable in the proximity to the coastline has many areas where the greater geological complexity occurs in the direction perpendicular to the coast line. This greater geological complexity translates into the need for better spatial sampling in this direction. A natural solution in seismic design is to acquire data with the navigation lines in the same direction of the greater geological complexity. However, when the shoreline is at a distance on the order of less than one cable, this solution gradually leads to compromises that could ultimately culminate in thereduction of the acquisition area, and therefore, of the image area. Other feasible solutions are to navigate in the direction parallel to the coast and to use a smaller separation of cables, or to use triple seismic sources. Another solution would be the acquisition of data with Ocean Bottom Cable (OBC) orOcean Bottom Node (OBN) technology or a mixed solution (streamer and OBC or OBN). However, with these othermethods it is difficult to reconcile the sampling and illumination requirements with the economic and/orenvironmental constrains.
One of the marine acquisition technologies useful to solve the previous critical points is to use the method of continuous line acquisition (CLA). This technology consists of acquiring seismic data during the turns for line changes and thus increasing the operational efficiency. However, the main motivation of this article is to illustrate and evaluate the implementation of this technology as an alternative solution in shallow water areas
Presentation Date: Tuesday, October 16, 2018
Start Time: 8:30:00 AM
Location: 210C (Anaheim Convention Center)
Presentation Type: Oral
We present an anisotropic rock physics model which can be used to estimate velocities for different facies types (sands, shales and carbonates). The model uses a combination of the joint Self Consistent, Approximation and Differential Effective Medium model (SCA/DEM) and the Hudson model for fractures. The SCA/DEM model is used to build the frame of the rock and the Hudson model adds fractures in 3 orthogonal directions with varying concentrations inducing anisotropy. Allowing the model parameters to change gives enough flexibility to the model to model different facies including sands and carbonates. The model has been tested against sand, shale and carbonate data from well logs in the Barents Sea and the North Sea. Anisotropy for this well was estimated using the method of White (1983). Results show a good fit between the rock model and the data.
Presentation Date: Thursday, October 18, 2018
Start Time: 8:30:00 AM
Location: 202A (Anaheim Convention Center)
Presentation Type: Oral
ABSTRACT: Fracture driver determinations are mainly focused on the factors which influence fracture intensities. A normalized averaged intensity can have more than one possible fracture spatial organization and hence the importance of combining intensity and cluster analysis to better model fracture interconnectivity in reservoirs. Mississippian Lime fracture cluster analysis using correlation count method was used in an area that covers a narrow central faulted area influenced by strike slip tectonics as well as the two adjacent blocks to the east and west of this area. Four main rock types with large contrast in porosity and permeability were identified: tripolitc chert, calcareous siltstone, fractured carbonate and limestone with fracture intensities ranging from 0.16 to 0.57 fractures/ft, respectively. Fracture cluster analysis shows a large contrast in fracture cluster orientation width (200 to 1500) and spacing between the faulted block and the eastern and western blocks. A significant diagenetic overprint makes cluster analysis very relevant when fracture intensity drivers are based on rock type.
Exploration and Production (E&P) activities take place across the globe. Environmental management is governed by national and regional laws and international standards, which draw red lines and establish management rules for emissions, wastewater and waste. Although international biodiversity management guidelines are in place, adherence in areas with high biodiversity value, either in terms of habitats or species, is complex and ALARP (As Low As Reasonable Practicable) impact targets are not easily established. A simple but effective approach, the Repsol Biodiversity and Ecosystem Services Tool (BEST-R), has been developed to meet this challenge for all Repsol E&P activities and has been evaluated by applying this tool to 15 projects at 7 operating assets.
Minimizing the footprint of marine operations in the O&G sector is of uttermost importance to ensure business sustainability. Oil spills due to a number of activities and hazards are one of the major concerns offshore. Risk assessments must carefully cover all possible control and recovery barriers and the appropriate response resources must be kept on guard against any event. The likelihood, consequences and vulnerability of the affected area shape the risk in any possible oil spill. Spillage rate and time of release depicture to a great extent the consequences of the spill, thus an early detection is crucial to minimize impact as well as to help reduce reaction time and resources scale for the responders.
An early detection tool was satisfactorily put in place either in offshore production rig and maritime terminal, with specific capabilities for automated (unmanned) detection, 24/7 recording, remote surveillance, alarm logging and very low threshold detection level in adverse weather conditions. This means a digital transformation in the surveillance of marine operations allowing the exploitation of data to get the information needed to improve Safety in operations. With a threefold approach for innovative environmental protection, asset risk/integrity assessment and transparency culture promotion, a detection system was co-developed by operator and vendor to meet assets and operations needs and produce a tailor-made product. Such a novel system combines wide-coverage radars together with high-precision infrared cameras commanded and integrated by intelligent algorithms. Lessons learnt out of event reporting from this tool will be shared to help reinforce the link between prevention and response policies and protocols.
Key tactical information for quick response, resources optimization, routine/critical operations monitoring, and real-time data sharing either internally or with third parties is yielded out of the System (HEADS) as a new input for a holistic and proactive approach towards asset protection.
Folger, M. (Repsol) | Alkatiri, F. (Repsol) | Nguyen, T. A. (Repsol) | Daungkaew, S. (Schlumberger) | Khunaworawet, T. (Schlumberger) | Duangprasert, T. (Schlumberger) | Paramatikul, R. (Schlumberger) | Dang, T. D. H. (Schlumberger) | Millot, P. (Schlumberger) | Shrivastava, C. (Schlumberger) | Mustapa, S. (Schlumberger) | Gok, I. M. (Schlumberger) | Vincent, R. (Petromac)
Deepwater reservoirs are known to have number of challenges associated with operations, evaluation and production potential. The thinly laminated reservoirs, or reservoirs associated with heterogeneous sands could add further challenges. Lateral and vertical continuity of the reservoirs control the real economic potential in many cases. Reservoir fluids and reserve cut-off are crucial information for reservoir development plan, and they are required at early stage during exploration campaign. In order to convert the challenging thinly bedded structures into commercial development potential, proper reservoir characterization with effective cost expenditure becomes critical. Flowing fluid to the surface is usually required for reserve certification as per the Securities and Exchange Commision (SEC) and Society of Petroleum Engineers (SPE) regulations. In many countries, full scale Well Testing is the only way to book the reserve. However, the cost to conduct this operation is quite substantial from few to ten millions of the US dollar depending on the number of testing zones on top of operation complexity. Alternative solution with lower cost is becoming important option, especially in deepwater environments. This paper presents an integrated workflow to use advanced formation evaluation logging information to help building the systematic approach to upscale the Interval Pressure Transient Test (IPTT) to the full scale Well Testing data. The actual field data from South East Asia was used to demonstrate this workflow.
In the first campaign in 2015, number of high resolution logs such as electrical borehole image logs and Nuclear Magnetic Resonance (NMR) logs were acquired prior to fluid identification and fluid sampling using wireline Formation Testers (FT). The IPTT and Vertical Interference Test (VIT) were the secondary objectives. However, the results from the first campaign illustrate an impressive reservoir data that can be obtained from a short pressure build-up after sampling. The vertical connectivity can be seen clearly in the pumping and build-up data. In the second campaign, more than 26 IPTT stations were planned which includes formation pressure, fluid identification, sampling, and pressure transient test with single 3D Radial inflatable packers and the focused sampling probe. The lessons learnt from previous campaign allows us to conduct the test in much more effective time, i.e. within 1-3 hours per station.
Due to complexity of deepwater sedimentations, there are more challenges to understand the flow potential for each tested interval. This is crucial information to derived effective permeability from the IPTT data. Other high resolution logs such as NMR and electrical borehole image logs were used to define bedding boundary. NMR measurement gives information of porosity-permeability, and in addition, rock quality can be estimated from NMR and borehole image logs. Later the log derived permeability will be compared to the upscale IPTT tests. The consistency between different data provides confident level for our upscaling method and workflow. This will be a first paper that present this systematic workflow for the challenging deepwater reservoirs.
The oil and gas industry, by default, has been pretty conservative when it relates to innovation and drastic changes in mind-set. Mainly focused on the costly drilling and completion steps, some of the "smaller" services have been ignored. As such, we have decided to take a deeper look at nano and micro sensored technologies in other industries and potentially replicate some of this innovation, allowing the industry to take "a step" closer to smarter zonal isolation.
In general, the industry is quite aware of well integrity issues that we face. Be it immediate (whilst drilling/completing), within the life of production or even during the abandonment phase. There are many statistics proving that on a global scale, there is well integrity and sustained casing pressure issues on about 30-60% of all drilled wells. And we can confirm that a majority of these are directly related to well-cementing, creating an immense impact(s), that can negatively influence overall HSE, loss of potential reserves and bottom line dollar-amount.
The ability to take a close look at well cementing has only proven feasible in a laboratory environment, beyond that, the knowledge and prediction of the actual state of the zonal isolation has proven difficult, confusing or costly.
Regardless of the improved best practices, enhanced logging tools or state-of-the-art technological advances in chemicals/systems – we still seem to have that unanswered "gap" – on what actually happened, when it happened and how to avoid it in the future.
This paper describes the background, the thought process and the potential advantage of the proposed well monitoring ideology and current R&D efforts to improve the cement isolation measurements and real time monitoring of its properties and integrity during the well life and after its abandonment, by sensoring it and communicating back to surface.
In some of the giant extra-heavy oil fields from the Orinoco Oil Belt (OOB), the challenge is to increase recovery over primary production by about 10%, to meet its ambitious development plan. To get this, it is necessary to apply EOR processes.
It is visualized the integral design of a cyclic steam stimulation (CSS) pilot test, using a high steam injection rate. It is identified and quantified the main variables and operational parameters affecting the performance of CSS, for an oil field at OOB.
The design of this pilot test covers the location of the area, visualization of thermal well, identification and quantification of the variables that potentially influence to a greater extent the performance of this technology, conceptual design of EOR surface facilities and a complete monitoring plan.
A cluster with 10 long horizontal wells of different lengths is evaluated. The variables studied are: specific steam flowrate per unit length of well, well length, and well thermal insulation. We apply design of experiments to select the combinations of the values taken for the different variables. The duration of the different stages in every cycle is given by previous results applying optimization of CSS to sector modeling.
The main constrains dictated for the thermal well are identified and taken into account to define the maximum steam injection and production rates for this test.
The pilot test is simulated for three complete cycles, with two approaches: High (2.2 – 3 bbl/day*ft) and Low (1.5 bbl/day*ft) specific steam flowrates. Important production variables as drawdown, bottom-hole pressure, field average pressure, gas oil ratio and water cut have been evaluated.
Results for the main operating parameters (High/Low approaches), and the economic evaluation, are shown. These results show once again that higher specific steam flow rates get higher recovery and are even more profitable.
The study encourages a review of the paradigm that limits steam injection rates in high-productivity projects currently underway at OOB. Additionally, it is identified that at present is the thermal well and not the surface facilities, which limit the application of CSS at higher rates, needing an urgent improvement in its concept.
The steam injection rate is conventionally expressed as daily rates (bbl/day), absolute amounts per unit thickness of formation (bbl/ft), etc. This practice creates misunderstandings, especially in the case of horizontal wells. The variable proposed in this study (specific steam flow rate per unit length of well) is valid for any type of well, and it has a physical significance related to well injectivity.
Another novelty introduced in this study is a higher specific steam flow rate (2.2-3 bbl/day*ft), between 50% and 100% higher than references found in the literature (1.5-2 bbl/day*ft).
Reveth, V. (Schlumberger) | Ortuno, G. C. (Repsol S.A.) | Bersaas, K. M. (Statoil ASA) | Escalante, J. R. Contreras (Schlumberger) | Barron, J. (Repsol) | Moretti, F. (Schlumberger) | Antunes, A. D. (Schlumberger)
In a Deepwater well off the Brazilian coast which presented a complex architecture with multiple drilling casings and liners, losses were expected during cement placement across a carbonate formation. This paper describes the use of a new real time monitoring and evaluation tool which takes the data acquired during the cement placement, then processes and simulates in real time to provide important job parameters such as estimation of fluid interface positions inside the casing and annular space, pressure match chart, density quality assurance and quality control (QA/QC), ECD and dynamic well security, among others.
This manuscript present two cases history where the operator and the service company work together to define a decision tree for the possible contingencies related to unwanted TOC based on mud losses or unplanned cement placement. Later during the operation the new tool combines the design data with the cement unit and rig acquisition data to compare the job measured surface pressure, density, flowrate and volume with predicted data from simulations. Finally based on the information of real time estimation of the TOC outside the pipe and annulus space observed during the job execution a contingency from a decision tree is taken.
The cementing service company provided real-time monitoring and evaluation tool that allowed the operator to identify the estimated TOC at the end of placement. With this information, the client was able to avoid the top of liner squeeze and save 2-3 days rig time Later a cement bond log showed that top of cement was found between the liner lap confirming the barrier element. In another case it was prevented leaving unplanned cement inside the casing with the analysis of the job and simulated pressure match trends at the end of the displacement and eliminated unexpected flat times for additional drill out time.
Real-time monitoring and evaluation is a tool that can be deployed not only in Deepwater wells in Brazil, but in any section of wells being drilled around the world on land, on the shelf or in Deepwater, where the operator wants to visualize ether the deviation of job execution from job design parameters or a prompt estimation of top of cement as a first level of detection for the well barrier placement just after bumping the plug. In addition having the real time dynamic ECD will also aid in avoiding any potential well control situations (including lost circulation) during the cement operations at any time during this critical activity