Electric Submersible Pumps (ESP) are commonly used artificial lift equipment in production wells. The ESP packer penetrator system is designed to carry the electric power cable that connects the electric motor in ESP to the surface control panel. Various chemicals downhole make up highly corrosive and hostile environments to the metal wires and their insulation materials for electric connectors. Many ESP failures could be attributed to packer penetrator failure due to corrosion of the electric connector beneath the ESP packer.
A method is developed to generate a low density gel system that isolates the electric connector from downhole chemicals in order to provide prolonged protections of electric connectors against corrosive atmospheres and chemical attacks. Mixture of low-density materials/composites are prepared on the surface and then pumped into targeted place through the bypass tubing. The mixture has low density so that it travels upwards in the wellbore and floats on the top of downhole fluids. Under a given well temperature, a rigid gel/composite system forms between the electric connector and the downhole fluids, isolating the electric connector from the hostile chemicals thus providing a better protection. We have developed the low density settable material and demonstrated its performance in the lab scale. It is also scaled up to a mocked up physical simulator to observe the flow dynamics and chemical reaction in realistic geometry.
Electric Submersible Pump (ESP) is an important artificial lift technology for boosting well production (Tacks 2009). Its main advantage over other artificial lift methods include high rate and the ability to produce wells to abonnement. An ESP system mainly consists of a centrifugal pump, a protector, power delivery cable, and a motor. The pump is used to lift well fluids to the surface. The motor provides the mechanical power required to drive the pump via the shaft. The power delivery cable provides a means of supplying the motor with the needed electrical power from the surface. The protector absorbs the thrust load from the pump, transmits power from the motor to the pump, equalizes pressure, provides/receives additional motor oil as temperature changes and prevents well-fluid from entering the motor. The pump consists of stages, which are made up of impellers and diffusers. The impeller, which is rotating, adds energy to the fluid to provide head, whereas the diffuser, which is stationary, converts the fluid kinetic energy from the impeller into head. The pump stages are typically stacked in series to form a multi-stage system that is contained within a pump housing. The sum of head generated by each individual stage is summative; hence, the total head developed by the multi-stage system increases linearly from the first to the last stage.
Douglas is an oil field in the Irish Sea where electric submersible pumps (ESPs) are used as artificial lift method. This paper presents the ESP failures and root causes in early stages of production, and the improvements implemented that contributed to the outstanding improvement in ESP run life. These improvements increased field production, minimized deferred production, and minimized workover costs.
Every ESP system pulled from the Douglas field was dismantled, and a failure analysis was performed to identify the failure root cause. When the root cause is confirmed, applicable equipment upgrades were recommended to address the failure modes and increase ESP run life. In order to monitor system performance, reliability was tracked and compared over the years. The ESP reliability was analyzed using data gathered from ESP run life and failure analysis covering more than 20 years of ESP operation in the Douglas field.
Failure analysis performed in the pulled strings indicated failures related to poor electrical power quality. A power study was performed on the Douglas platform, and it was observed that the wells exhibited natural system resonance frequency amplifying drive harmonics. Resonant peak frequencies were observed between five and seven kilohertz, and voltage impulses were observed up to nine kilovolts. Such impulses were weakening insulation in some downhole components, such as penetrators, cables, and motors. Following the recommendations from the study, load filters were installed in every well to eliminate voltage overshoots. The filters provided cleaner voltage and current waveforms to the system, power cable, and at the motor terminals.
In addition to the power supply issues, it was noted that there was H2S contamination in the protectors and motors pulled from the field. In order to increase ESP reliability, an advanced H2S scavenger protector design was introduced. The advanced protector has features that delay the ingression of H2S into the motor and copper liners that serve as sacrificial parts to be consumed by H2S.
The solutions proposed for ESP operation in combination with ESP design improvements helped to improve ESP reliability considerably allowing ESP systems to achieve outstanding run lives in the Douglas field.
Knowledge Sharing ePoster Sessions An ePoster, presented on a digital screen offers the added benefit of animation and video to enhance the visual experience and provide greater interactivity between attendees and authors. During the ePoster session, authors will present their technical papers at designated ePoster stations. Attendees are encouraged to attend the sessions for more knowledge sharing and networking opportunities. Authors will be informed of their respective presentation schedule by early October 2017. An ePoster, presented on a digital screen offers the added benefit of animation and video to enhance the visual experience and provide greater interactivity between attendees and authors.
AbstractA reservoir-conditions coreflood study was undertaken to assist with design of drilling and completion fluids for a Norwegian field. Multiple fluids were tested, and the lowest permeability alterations did not correlate with the lowest drilling fluid filtrate loss volumes. This paper will examine the factors which contributed to alterations in the core samples.A series of corefloods were carried out using core from 2 formations and different drilling fluids. Separate tests were carried out using drilling fluid alone and the full operational sequence. Filtrate loss and permeability measurements combined with interpretative analyses to understand what happened in the near-wellbore. Micro-CT "change maps" gave 3D visualisations of the thickness of operational fluid cakes and extent of retention/clean-up – valuable insights into factors that influence hydrocarbon recovery.All drilling fluids tested had "normal" filtrate loss volumes, with one having notably higher losses with a particular formation. Normally this would be considered a bridging issue and "fixed", but those tests showed comparable or slightly lower alterations in permeability. Analysis showed that, despite deeper constituent infiltration, they were not contributing significant extra damage or retention; the nature of the drilling fluid attachment and cake seemed to be more relevant here than depth of invasion. Other examples will illustrate that the impact of drilling fluid infiltration and retention can range widely, and that there are more key factors than simply filtrate loss volume.Results showed that focusing on the metric of filtrate loss alone may increase risk during drilling fluid selection. Understanding the relationship between filtrate loss, permeability/inflow alteration, retention/clean-up after production is important in selecting fluids as well as giving a better understanding of where improvements can be made. 3D visualisations of the alterations caused by drilling fluid allow conclusions to be drawn when previously there would be speculation.
Fleming, Niall (Statoil) | Moland, Lars G. (Statoil) | Svanes, Grete (Statoil) | Watson, Russell (Schlumberger) | Green, Justin (Corex) | Patey, Ian (Corex) | Byrne, Michael (LR Senergy) | Howard, Siv (Cabot)
Valemon, operated by Statoil, is a high-pressure/high-temperature (HP/HT) gas/condensate field on the Norwegian Continental Shelf. Production started at the beginning of 2015 from a development consisting initially of cased-and-perforated wells. However, during early field development, the original concept was for a standalone-screen (SAS) lower completion. A potassium/cesium (K/Cs) formate water-based system with a density of 2.02 specific gravity (sg) was considered as a candidate drilling-and-completion fluid for the wells completed with screens, one of which could potentially be suspended in formate brine for up to 10 months before the arrival of the platform and before cleanup and the onset of production. An unknown was the possibility for any near-wellbore interaction with these fluids during extended contact and the possible detrimental impact on productivity. Computational-fluid-dynamics (CFD) modeling was performed to determine the length of time formate would be in contact with the near wellbore, demonstrating that, especially for the lower-permeability intervals, a contact time of approximately 45 days was a possibility. In light of this, a sequence of corefloods was performed that involved extended soaks in formate along with pre- and post-test analyses to identify potential damage mechanisms. Those identified included kaolinite dissolution, precipitation of barium and cesium silicate, and swelling of kaolinite because of the incorporation of potassium and cesium into the kaolinite lattice. To confirm the findings from the CFD and coreflood modeling, a field review was made of Statoil's experiences with suspending wells for extended time in formate before cleanup and production. The field review demonstrated positive experiences in the use of formates in suspended wells with respect to productivity. Lower than expected productivity was experienced for some wells, but this could not be related conclusively to the use of formates. This paper provides an overview of lessons learned from coreflooding, CFD modeling, and actual field data on wells suspended in formate before cleanup and production.
The Rhyl field was discovered in 2009 and received development approval in 2012. It is located 11 km north of the North Morecambe field. The North and South Morecambe fields were discovered in the 1970s, with some 7 Tcf of gas initially in place. Production from the Rhyl field extends the longevity of these assets. Vertical and horizontal variations in CO2 content in the Rhyl field were assessed across the Triassic Ormskirk sandstone, the upper member of the Sherwood sandstone group. The Ormskirk sandstone formation represents the principal reservoir target in the East Irish Sea, comprising high-porosity aeolian and fluvial sandstones with variable grain size and playa mudstones.
This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 166497, "Mapping CO2 in Real Time in Hydrocarbon Reservoirs With Downhole Fluid Analysis: First Successful Experience in the East Irish Sea, UK Continental Shelf," by B. Quayle, S. James, and M. Quine, Centrica Energy, and I. De Santo, P. Jeffreys, and J.Y. Zuo, Schlumberger, prepared for the 2013 SPE Annual Technical Conference and Exhibition, New Orleans, 30 September-2 October. The paper has not been peer reviewed.
This paper describes the first successful attempt on the continental shelf offshore UK to map carbon dioxide (CO2) in real time while logging during a drilling campaign in the East Irish Sea. Reservoirs in this sea’s basin contain varying proportions of CO2, nitrogen (N2), and hydrogen sulfide (H2S), in addition to oil and methane. Two of these wells develop the Rhyl gas field. Downhole-fluid-analysis (DFA) technologies were deployed with a wireline-formation-testing (WFT) tool to measure CO2 content accurately downhole.
The Rhyl field was discovered in 2009 and received development approval in 2012. It is located 11 km north of the North Morecambe field. The North and South Morecambe fields were discovered in the 1970s, with some 7 Tcf of gas initially in place. Production from the Rhyl field extends the longevity of these assets.
Vertical and horizontal variations in CO2 content in the Rhyl field were assessed across the Triassic Ormskirk sandstone, the upper member of the Sherwood sandstone group. The Ormskirk sandstone formation represents the principal reservoir target in the East Irish Sea, comprising high-porosity aeolian and fluvial sandstones with variable grain size and playa mudstones.
Gas Composition in the Rhyl Field
The composition of the gas found in Rhyl includes both hydrocarbon and nonhydrocarbon components such as N2 and CO2. The N2 is derived from late-stage hydrocarbon generation, while isotope data indicate that the CO2 has a magmatic origin. It is believed to have been exsolved from the magma of a series of Tertiary dolerite intrusions into the Ormskirk sandstones in close proximity to the Rhyl field. The samples collected during the drillstem test conducted on exploration Well 113/27b-6 provided several qualitative indications of a higher CO2 content than was originally expected from the correlation with the nearby North Morecambe field: a high gas density measured at the separator and difficulty in sustaining a flare.
Mishra, Vinay K. (Schlumberger) | Cañas, Jesus A. (Schlumberger) | Betancourt, Soraya S. (Schlumberger) | Dumont, Hadrien (Schlumberger) | Chen, Li (Schlumberger) | De Santo, Ilaria (Schlumberger) | Pfeiffer, Thomas (Schlumberger) | Achourov, Vladislav (Schlumberger) | Hingoo, Nivash (Schlumberger) | Zuo, Julian Y. (Schlumberger) | Mullins, Oliver C. (Schlumberger)
In deepwater and other high-cost environments, reservoir compartmentalization has proven to be a vexing, persistent problem that mandates new approaches for reservoir analysis. In particular, methods involving reservoir fluids can often identify compartments; however, it is far more desirable to identify reservoir connectivity. Downhole fluid analysis (DFA) has enabled cost-effective measurement of compositional gradients of reservoir fluids both vertically and laterally. Modeling of dissolved gas-liquid gradients is readily accomplished using a cubic equation of state (EOS). Modeling of dissolved solid (asphaltenes)-liquid gradients can be achieved using the newly developed Flory-Huggins-Zuo equation of state (FHZ EOS) with its reliance on the nanocolloidal description of asphaltenes within the Yen-Mullins model. The combination of new technology (DFA) and new science (FHZ EOS) provides a powerful means to address reservoir connectivity. It has previously been established that the process of equilibration of reservoir fluids generally requires good reservoir connectivity. Consequently, measured and modeled fluid equilibration is an excellent indicator of reservoir connectivity. However, some reservoir fluid processes are faster than equilibration rates of reservoir fluids. The often slow rate of fluid equilibration makes it a suitable indicator of connectivity. Consequently, measurement of disequilibrium can still be consistent with reservoir connectivity. Moreover, the two fluid gradients, dissolved gas-liquid versus dissolved solid-liquid can be separately responsive to different fluid processes, thereby complicating understanding. A workflow is developed, the DFA reservoir connectivity advisor, to enable interpretation of the implications of measured fluid gradients specifically with regard to reservoir connectivity. Reservoir connectivity is difficult to establish in any event; analyses of fluid gradients can be placed in a context of the probability of connectivity, thereby significantly improving risk management.
This paper describes th
e first successful attempt in the UK Continental Shelf (UKCS) to map CO2 in real time while logging during Centrica's recently concluded four well drilling campaign in the East Irish Sea, offshore north-west England. The East Irish Sea basin is characterised by a range of source rock types, prolonged history of hydrocarbon generation, and Tertiary igneous intrusion. As a result, reservoirs contain varying proportions of carbon dioxide (CO2), nitrogen (N2), and hydrogen sulfide (H2S) in addition to oil and methane. Two of these wells will develop the Rhyl gas field that was discovered in 2009 and found to contain high concentration of methane and CO2 and some N2. An early and accurate understanding of gas composition and variation in such newly discovered fields is critical to reserves estimates, and scheduling and optimizing gas processing at the onshore North Morecambe Terminal.
CO2 had been recognised as a risk prior to drilling the Rhyl exploration well due to the relatively low CO2 content in the neighboring North Morecambe field. During logging and testing several qualitative indications of a higher CO2 content were identified: a high gas density measured at the separator and difficulty in sustaining a flare. Traditionally, the presence of CO2 has been assessed and quantified via lab analysis on samples acquired by both wireline formation testing tools and well tests. Reliable quantification of CO2 from reservoir fluid samples can be difficult due to mud filtrate contamination and because it readily dissolves in produced formation water.
In many CO2 rich reservoirs, compositional gradients are observed with higher CO2 concentrations at the base of the gas column. The two Rhyl development wells provide an opportunity to improve our understanding of the CO2 distribution throughout the field. The latest generation of Downhole Fluid Analysis (DFA) technologies was deployed with the Wireline Formation Testing (WFT) tool. Such technology uses a dual spectrometer system (filter and grating) to accurately measure CO2 content downhole, prior to scavenging. A dedicated channel for the CO2 absorption peak is complemented with dual baseline channels on either side to subtract the overlapping spectrum of hydrocarbon and small amounts of water. The DFA sensor was used at each sampling station during the WFT run of the first Rhyl development well measuring an almost constant vertical CO2 distribution. DFA data was complemented by pressure and pressure gradient analysis and integrated with high definition fullbore microresistivity images, allowing a better understanding of the gas composition across the Rhyl field, hence removing a significant project risk.
Lower to Middle Carboniferous shales represent the most prominent shale play in the UK. In the East Midlands region, the Widmerpool Gulf contains proven oil-prone Carboniferous source rocks that sourced producing petroleum fields and seep bitumens such as at Windy Knoll in Derbyshire. This study is based upon new analyses of samples obtained from the British Geological Survey (BGS) for the Duffield borehole that was drilled in the Widmerpool Gulf. These new results, in conjunction with available legacy data, were used to determine the organic geochemical and mineralogical properties of the Upper Carboniferous sediments intersected in this well and for subsequent comparison against the criteria characteristic of producing North American shale gas plays.
By projecting stratigraphic thicknesses from a BGS isopachyte map of the basin, an estimate of post-Variscan burial and erosional events were predicted. Based upon the Duffield borehole data, a 1D model of its burial history was built using Zetaware?s Genesistm software. This basin modelling established the thermal history of the preserved borehole section with results indicating is likely potential for an unconventional oil and gas play in the Widmerpool Gulf.
Basin modelling with associated vitrinite reflectance data suggest the burial history of the Widmerpool Gulf involved 1150m (1.15km) and 2760m (2.76 km) of erosion for the Paleozoic and Tertiary events respectively. The modelled scenarios propose that the main maturity for the Widmerpool Gulf was during the Upper Cretaceous maximum burial event, which overprinted any maturity from the minor burial during the Variscan