Most of ConocoPhillips' oil and gas production by the end of the next decade will come from its unconventional operations. But, for the near-term, the Houston independent will rely on its conventional assets as it seeks to keep spending in check, decline rates low, and cash flow on the rise. "The decline rate of our new production is lower than most of our competitors because it comes from diverse sources," and this new production "isn't all high-decline unconventional," said Matt Fox, ConocoPhillips executive vice president and chief operating officer, during the company's analyst and investor meeting presentation in late November. Executives came together at the event to outline the company's operating and financial plan for 2020–2029. ConocoPhillips plans to spend $2.4 billion/year on conventionals during the 10-year period, maintaining stable production of more than 750,000 BOE/D.
Remya Ravindran Nair, Evgenia Protasova, Torleiv Bilstad, and Skule Strand, University of Stavanger Summary This research focuses on membrane-separation efficiencies by adjusting the ionic composition of deoiled produced water (PW) and evaluates the possibility for smartwater production from PW for enhanced oil recovery (EOR) in carbonate reservoirs. Key characteristics of smartwater for carbonate reservoirs are increased concentrations of divalent ions and low concentrations of monovalent ions compared with seawater. In this research, PW was pretreated with media filters, which resulted in 96 to 98% oil removal. This deoiled PW was used as feed for nanofiltration (NF) membranes. NF-membrane performance was evaluated in terms of flux and the separation efficiencies of the key scaling ions calcium (Ca) and barium (Ba). No membrane fouling was observed during the experiments. The results showed no Ca dissolution, which could affect chalk-reservoir compaction. A process scheme is proposed for smartwater production by ionic selection from seawater and PW at an operating pressure of 18 bar. Energy-consumption analysis for smartwater production before membrane treatment concluded NF to be economic over other desalination technologies. The power consumed by NF membranes for smartwater production at 18 bar is calculated at 0.88 kWh/m Introduction PW is one of the major waste streams from the oil and gas industry and should be managed in an environmentally sustainable manner. PW treatment is concerned with contaminants such as solids and residual oil, together with production chemicals (Fink 2012). The current water/oil ratio (WOR) in oil production is 2:1 to 3:1 worldwide. Onshore-treatment costs of PW from the North Sea differ from 0.19 to 3.40 USD/bbl of PW (Duhon 2012).
Imaging the geology subsalt and at the transition between extra-salt and subsalt has been a challenge at Mad Dog even with extensive seismic data coverage, including two WATS surveys and multiple NATS surveys. WATS acquisition and TTI velocity model processing generated major improvements in the image at Mad Dog. One of the observations of a previous TTI project is the presence of a strong orthorhombic anisotropic effect in a salt mini basin above the field. This finding led to the decision to reprocess the Mad Dog data with a tilted orthorhombic (TOR) velocity model. The main objective of this project is to build an orthorhombic velocity model with nine parameters compared to five with the TTI processing. The TOR anisotropic parameters are generated with the latest FWI and tomography techniques and take guidance from the stress field from a geomechanical model. The outcome of the project is very encouraging with results including better constructive imaging in crucial areas of the field, an incremental increase in signal-to-ratio everywhere and increased fault resolution. The TOR velocity model will be used to migrate a future ocean bottom nodes survey to address some of the remaining imaging challenges.
Presentation Date: Wednesday, October 17, 2018
Start Time: 8:30:00 AM
Location: 208A (Anaheim Convention Center)
Presentation Type: Oral
Shale is a general term used for argillaceous (clay-rich) rocks which are the most abundant sediment on the earth. It is believed that clay rich rocks comprise more than 50-75% of the geologic column. Shale has very varying petrophysical and mechanical properties. Shale is in the most cases acting as a trap or seal for hydrocarbon migration, but has also in more recent years been targeted as a reservoir target in some basins. In some wells it has been observed on cement bond logs that shales in uncemented intervals have moved in and closed the annulus. Pressure communication testing has been performed on these sections and the sections has been qualified as well barrier elements (
In this paper we will discuss shale creep and other shale deformation mechanisms and how an understanding of these can be used to activate shale that has not contacted the casing yet to form a well barrier. We have developed a numerical model based on first order principles to better understand the mechanical deformation process. We are also supporting the modeling results with laboratory experiments, before we discuss a couple of field cases where shale intervals have been activated and verified to have formed a well barrier as part of the well construction process in new wells.
Aamodt, G. (ConocoPhillips Skandinavia AS) | Abbas, S. (ConocoPhillips Co) | Arghir, D. V. (ConocoPhillips Skandinavia AS) | Frazer, L. C. (ConocoPhillips Co) | Mueller, D. T. (ConocoPhillips Co) | Pettersen, P. (ConocoPhillips Skandinavia AS) | Prosvirnov, M. (ConocoPhillips Skandinavia AS) | Smith, D. D. (ConocoPhillips Co) | Jespersen, T. (Halliburton Co.) | Mebratu, A. A. (Halliburton Co.)
This paper discusses a field case review of the processes used to identify, characterize, design and execute a solution for a waterflood conformance problem in the Ekofisk Field that developed in late 2012. The Ekofisk Field is a highly-fractured Maastrichtian chalk reservoir located in the Norwegian sector of the North Sea. Large scale water injection in the field began in 1987 and overall the field has responded well to waterflood operations. However, fault reactivation coupled with extensive natural fractures and rock dissolution has resulted in some challenging conformance issues. In late 2014, a solution was executed to control this problem. Details of the diagnostic efforts and how this data was used to identify, characterize and mitigate an injector/producer connection through a void space conduit (VSC) will be outlined and discussed. These diagnostics include pressure transient analysis (PTA), interwell tracers, injection profiles, seismic mapping, fluid rate analysis, fluid composition and temperature monitoring. The importance of this data analysis is the key element necessary to select an effective solution.
The selected approach involved pumping a large tapered nitrified cement treatment into the offending injector, which is believed to be the single largest nitrified cement operation ever pumped within the oil industry. Because of extremely rapid communication with an offset producer, a protective gel was used to reduce the risk of cement entry into that producer. A brief review of alternative mitigation options and the reasons for selecting the nitrified cement treatment will be discussed. Additionally, a complete review of the shutoff technique, product, damage mitigation strategy, and complications associated with timing and coordination in an offshore environment will also be discussed. Finally, a summary of lessons learned, job execution observations, post-treatment performance results over the past three years, and forward plans will be presented. Based on these results it is believed that there are a number of opportunities to add strong value through conformance engineering.
De Gennaro, S. (Shell U.K. Limited) | Taylor, B. (Shell U.K. Limited) | Bevaart, M. (Shell U.K. Limited) | van Bergen, P. (Shell U.K. Limited) | Harris, T. (Shell U.K. Limited) | Jones, D. (Shell U.K. Limited) | Hodzic, M. (Shell U.K. Limited) | Watson, J. (Shell U.K. Limited)
ABSTRACT: The Shearwater field located in the UK Central Graben represents one of the most challenging high-pressure, high-temperature (HP/HT) developments of its kind in the North Sea. During production, the strong depletion of the Fulmar reservoir caused a number of geomechanical-related problems, including the failure of the initial development wells, and consequently, loss of production. In order to reinstate production at Shearwater, five infill wells have been drilled and completed successfully. This success was largely attributed to a multidisciplinary effort to understand the post-production changes of the overburden. In this paper, a comprehensive 3D geomechanical model is presented that was used as a key design foundation for safe HP/HT well delivery. The model results and interpretations are discussed, and a summary of the current understanding of the evolution of the overburden from a geomechanical perspective is provided. The challenges associated with infill drilling and, in particular, the loss of fracture gradient and the closure of the drilling mud weight window between this and pore pressure, and how these have added complexity to the drilling practices are described. Finally, key technologies implemented to overcome these issues including Managed Pressure Drilling, Drill-In Liner and Wellbore Strengthening are discussed.
The Shearwater field located in the UK Central Graben represents one of the most challenging high-pressure, high-temperature (HP/HT) developments of its kind in the North Sea. At the time of the initial development, elevated pressures in excess of 15,000 psi and temperatures greater than 350°F, and structural geology complexity, posed major technical challenges to Shearwater. These challenges involved all aspects of well construction and production in HP/HT conditions. Despite the challenges, all initial development wells were drilled successfully.
During the first years of production, and similar to other HP fields, reservoir pressures dropped rapidly to 8,000 psi on average. The strong depletion of the reservoir, in combination with the high compressibility of the reservoir rock, resulted in compaction of the Fulmar sandstones and led to displacements, deformations and stress changes in the overburden rock. Compaction-induced stress changes in the overburden (“stress arching”) were the driving force for a number of geomechanical-related subsurface problems. During 2004-2007, it resulted in four production liners being sheared due to slippage along faults or bedding planes near the crest of the structure. Furthermore, over time, some initial development wells then experienced rapid A-annulus pressure increases, suggesting a leak of the production casing at Hod Chalk Formation level.
Nair, Remya Ravindran (Department of Mathematics and Natural Science) | Protasova, Evgenia (Department of Mathematics and Natural Science) | Bilstad, Torleiv (Department of Mathematics and Natural Science) | Strand, Skule (Department of Petroleum Engineering, University of Stavanger)
Produced water (PW) management and reuse of PW has economic and environmental benefits compared to PW discharge. This research focuses on membrane separation efficiencies in adjusting the ionic composition of de-oiled PW and evaluating the possibility for smart water production from PW for enhanced oil recovery. Key characteristics of smart water for carbonate reservoir is increased concentration of divalent ions and depletion of monovalent ions.
Dual media is used for oil removal from PW. De-oiled PW is feed for Nanofiltration (NF) membranes for separation of barium and calcium ions. Combination of NF retentate with seawater (SW) as feed and NF permeate from PW is also considered. PW permeate is mixed with SW spiked with determining multivalent ions, sulfate or phosphate, which alter wettability of oil reservoirs.
Currently, smart water is produced by adding chemicals to fresh water or low total dissolved solids (TDS) water produced by reverse osmosis (RO) or flash distillation. Using de-oiled PW as feed to NF will reduce power consumption, footprint and chemicals. PW can be reinjected into reservoirs after removing scale-causing ions. By injecting low barium and calcium PW brines, the frequency of scale squeezes will decrease. Membrane performance is evaluated for flux and separation efficiencies of calcium and barium. Barium concentrations in synthetic PW is increased 20 times the original concentration in Tor Field in North Sea, for evaluating NF separation efficiency. Negligible amount of barium is present in NF permeate at pressures of 8-12 bars resulting in a permeate flow rate of 200 L/h for a membrane area of 2.6 m2.
Increased sulfate concentration in smart water enhances recovery by 40 % of original oil in place. However, BaSO4 scalingcan be initiated even with negligible barium concentration if high sulfate level is present in the injected brine. The novelty of this research resides in the use of non-precipitating phosphate replacing sulfate for smart water production, simultaneously decreasing barium concentration and scaling potential of PW. However, precipitation of calcium occurred in presence of high concentration of phosphate. Power consumed by NF membranes for smart water production is calculated at 0.37 kWh/m3.
Ronald, Andy (BP) | Han, Xiaogang (BP) | Webster, Mike (BP) | Zett, Adrian (BP) | Howard, Rodney (Halliburton) | Love, Alexandra (BP) | Lavery, David (Halliburton) | Guo, Weijun (Halliburton) | Quintero, Luis (Halliburton)
The Machar oil field is part of a collection of salt diapir structures in chalk formations in the UK Central North Sea. Water-flood production began in 1998 and historically Pulsed Neutron Logging (PNL) was used to track GOC's, WOC's and evaluate up-dip production targets prior to development. Now, towards the end of the decline stage, attention is focused on the timing of depressurisation, with PNL data used to calculate Sorw and Sorg for SCAL validation and full field modelling to maximize recoverable reserves. Different vintages of pulsed neutron data have been used in the workflow to guide the development of new acquisition and analysis techniques, which aim to minimize subsea rig time without compromising the value of information extracted from the data.
While Sigma is still a reliable nuclear attribute in determining saturation changes in areas imbibed with high formation water salinities, it has its limits in other parts of the field. This paper will present the use of “forensic” fluid identification information, water salinity in particular, to constrain the Sigma model and its use in quantitative evaluation. Other nuclear attributes are screened, characterized and described for further use in numerical evaluation.
To address the displacement complexity, in particular the variable salinity across the well's stratigraphy, other nuclear attributes were selected to reduce the uncertainty around residual oil to water (Sorw) calculations. While C/O logging does offer an independent salinity option, the method suffers from its slow logging speed requirement that is not practical during subsea well work operations. Instead of continuous and multiple C/O passes, a stationary methodology was developed to test the Sorw at suitable points. The methodology was validated against multiple passes over short intervals and in combination with other nuclear attributes integrated into an interpretation workflow. Further investigation of yard and field data of a number of nuclear attributes, indicates that combining stationary Inelastic with continuous Capture Yield data will reduce both the uncertainty around Sorw and the rig time. Of particular use is the Chlorine Yield that can be used quantitatively for such applications in chalk reservoirs.
This paper will describe the approach taken to drive new data acquisition to minimize the risk in subsea well work by reducing the logging time along with data integration into the reservoir model to improve depressurization timing and maximize field recovery.
The Mungo Field is a medium-sized oil field with a primary gas cap located in the Central North Sea. It has been developed as part of the Eastern Trough Area Project (ETAP) via a Normally Unmanned Installation (NUI) which is positioned directly above the field, with production tied back ca. 20 km to the ETAP Central Processing Facility (CPF).
Hydrocarbons are trapped in a pierced four-way dip closure against the Mungo salt diapir. The principal reservoir of the Mungo field is the steeply-dipping Palaeocene sands of the Sele, Lista and Maureen Formations, which overlie the Ekofisk, Tor and Hod Formations of the Chalk Group. The Palaeocene sandstone reservoir has been developed under combined water and gas injection since 1998. The underlying tight Chalk reservoir contains a poorly understood but potentially very substantial oil resource (estimated at 30 – 300 MM.bbls STOIIP). Direct development of the Chalk within the Mungo field has been very limited to date, with little offtake and few completions.
There have been a number of key challenges to overcome in order to demonstrate that the Chalk can be efficiently developed on Mungo. These challenges include the ability to achieve economic well production rates combined with demonstrable recovery of oil from the low permeability chalk matrix, given that there is very little evidence of natural fracturing. This is most accurately described in the definition and selection of an appropriate and efficient completion approach; a process and case history which this paper will fully detail. There are several features that make development of the Mungo Chalk both appealing and compelling, including the proximity/connection to existing infrastructure (with reducing throughput) and penetration of the Chalk by some existing Mungo development wells. This combination offers a unique potential suite of opportunities for low cost intervention, appraisal and subsequent development via recompletion.
In 2015, BP performed a Chalk appraisal test in an existing Mungo producer, W169 (22/20-A19), including the pumping of two distinct acid fracturing stages, a flow-back/clean-up, stable rate well-test and a long term shut in for a PBU. The W169 well was selected as the candidate well, as it intersected 220 m of the chalk sequence, including the Hod, Tor and Ekofisk formations. This paper presents the full sequence and details of this Mungo Chalk reservoir evaluation process. The information provided will describe the approaches taken to the design, the planning and the execution of cost-effective stacked, multi-zone acid-fracturing operations. Finally, the paper will close-out with the results of the operations and post job analysis, and provide an overview of future potential that has been unlocked by this sequence of operations.
Completion and intervention costs across the North Sea are at an all-time high and continue to challenge development economics; this has been exacerbated recently by a deteriorating oil price making cost-effective completion and intervention operations even more challenging. Typically at times such as these, the industry turns to the fracturing and stimulation process to maximise the return from existing assets and new wellbores. While this method continues to be feasible, increasingly this can only be achieved through challenging existing conventions and applying increasingly innovative approaches to the principal aspects and assumptions applied to the operations themselves; namely the deployment and the effectiveness of such operations in the field.
As the cost of a fracturing and stimulation execution mounts, due to numerous factors, including the efficiency of the service itself, available/economic well intervention capability, provision of sufficient accommodation (somewhat surprisingly/unhelpfully) and an ability to flow-back and clean-up in an efficient and effective manner. This paper will provide examples and case histories, across a number of our North Sea operations, which challenge and optimise each of these areas and demonstrate a number of mechanisms and approaches that have successfully been applied in order to reduce overall costs.
Some of the examples include a case history of the use of a boat (stimulation vessel) to boat (intervention vessel) stimulation approach, in order to eliminate secondary rig costs and thereby maximise the economics. Consideration of the use of a rig-based stimulation capability vs. extensive boat operations, efficient and cost effective well recompletion approaches and a suite of incremental improvements born out of continued North American solution development and deployment, such as the use of expandable packers and ball-drop matrix stimulations. Increasing the effectiveness of fracturing and stimulation (and maximising the productivity of each and every individual wellbore) is an obvious approach to improving economics and can be achieved in any number of ways. Again this paper will present a suite of examples and case histories of where this has already been achieved, across a number of our North Sea operations.
The current ‘perfect storm’, of a low oil-price environment combined with high industry contractual costs, is forcing all operators to become increasingly innovative in their pursuit of economic resource development across the North Sea. This paper presents a number of examples of innovation and cost-saving approaches that have been employed in order to achieve such economic intervention and provide further insight into the additional development potential and opportunity that may exist across this varied asset base.