Cairn Research (United Kingdom)

Super-resolved microscopy techniques have overcome the diffraction limit to provide image resolutions approaching the scale of fluorescent labels. However, many of these techniques require significant experimental resources and expertise and impose long image data acquisition times, making it difficult to acquire super-resolved data from sufficiently large sample numbers to overcome intrinsic biological variation. We have worked to make stimulated emission depletion (STED) microscopy and single molecule localisation microscopy (SMLM) more straightforward to implement and more practical to image larger numbers of cells. Here we present work in progress developing easySLM STED and easySTORM, including a new modular microscope frame that we believe can make it easier to prototype microscopy techniques and to implement and maintain them in lower resourced settings.

Abstract We applied a recently introduced method to complete a feasibility assessment and design a stress testing campaign in a deep-water field in West Africa. We first reviewed the previous—and unsuccessful—campaign. Test data were inverted together with a priori knowledge from an independent geomechanical study to develop an understanding of the ambient conditions. Based on this understanding, the current campaign's chance of success (COS) was estimated to be 10%, with 1,000 psi of pressure capacity lacking to reach 95%. By analyzing the sensitivity of the risk to formation properties and design parameters, we identified various options to prevent this high, yet seemingly controllable, risk of test failure. Among them, a 1.7-ppg increase of mud density, expected to increase the COS to 80%, was deemed most effective and implemented. With 4 successful tests out of 10, the second campaign was more successful than the previous one. Yet this success rate was lower than anticipated. We inverted the second campaign's test data to revise our understanding of the in situ conditions. Our main findings are that, for this particular case, (i) the magnitude of the minimum horizontal stress was significantly higher than initially thought, (ii) the minimum horizontal stress and the horizontal stress ratio appeared to be anticorrelated, and (iii) the COS was extremely sensitive to the minimum horizontal stress. The conditions solved using the second campaign's dataset also explained the first campaign's negative outcome. This case study demonstrates that (i) the proposed planning method enables return of experience to be captured and leveraged from one test, or one series of tests, to the next, and the design of formation stress tests to be optimized, leading to an improved success rate of formation stress tests; and (ii) the proposed inversion scheme allows insight to be gained from both successful and unsuccessful tests, including in formation conditions other than the minimum horizontal stress.

Abstract Understanding conditions at the grounding‐line of marine‐based ice sheets is essential for understanding ice sheet evolution. Offshore northwest Greenland, knowledge of the Last Glacial Maximum (LGM) ice sheet extent in Melville Bugt was previously based on sparse geological evidence. This study uses multibeam bathymetry, combined with 2‐D and 3‐D seismic reflection data, to present a detailed landform record from Melville Bugt. Seabed landforms include mega‐scale glacial lineations, grounding‐zone wedges, iceberg scours, and a lateral shear margin moraine, formed during the last glacial cycle. The geomorphology indicates that the LGM ice sheet reached the shelf edge before undergoing flow reorganization. After retreat of ~80 km across the outer shelf, the margin stabilized in a mid‐shelf position, possibly during the Younger Dryas (12.9–11.7 ka). The ice sheet then decoupled from the seafloor and retreated to a coast‐proximal position. This landform record provides an important constraint on deglaciation history offshore northwest Greenland.

Abstract This paper uses case studies to showcase the techno-economic impact of insert anchor and portable foundation on the development of marginal fields. Case studies are also included for unconventional surface pumping unit – Linear rod pump and hydraulic rod pump in the development of multiple wells from a single wellpad. Cairn India Ltd. is developing the southern part of its RJ-ON-90/1 block consisting of multiple geographically dispersed marginal fields, with small oil pool and varying crude properties. These fields consist of wells from exploration and appraisal era (some as old as 20xx[AD1]) completed for a natural lift with no provision for installing artificial lift system. Later, it was recommended to install Sucker Rod Pump (SRP) as the most suitable Artificial Lift (AL) system. Conventionally sucker rod down-hole pump is installed by running a barrel assembly on the bottom of tubing and plunger assembly at bottom of rod string. However, in an insertable sucker rod pump (ISRP), the entire pump assembly is run-in at the bottom of rod string and is landed on pump seating nipple (PSN) which was originally installed in the tubing string. Hence, installing SRP would require an expensive work-over operation. As the oil prices dropped, the economics of work overs became less justified. Options reviewed to improve the field economics included the use of Insertable pump anchor for installation of through tubing down-hole pump in existing well. This method allows setting the down-hole pump in tubing string without any requirement of pump seating nipple. The anchor provides the flexibility of pulling out and re-installing pump with the new or redressed system in case of pump malfunction or pump size modification etc. Extended application of insert anchor includes flow-back of hydraulic-fractured wells and extended well testing in exploration fields. It provides the flexibility of changing pump size based on reservoir response at the later stage. The multiple set-reset mechanism of insert anchor enables identifying tubing leaks and setting the pump above it. A portable concrete foundation against the conventional concrete base used for surface unit erection provides the flexibility of transporting the foundation between different locations. The foundation can be de-mobilized while placing the work-over rig, which otherwise requires disassembling fixed foundation. The same foundation can be used at multiple well sites saving on the cost of construction and reduced lost production time. On multi-well welllpad system, erection of conventional surface pumping unit on adjacent wells came as big challenge due to space constraint between the wells. Moreover, in the case of any well intervention like work-over, rod change etc. the nearby units requires to be disassembled adding to oil loss. Considering these problems operator decided to look into unconventional surface pumping unit e.g linear rod pump and hydraulic rod pump for the well pad systems.

Abstract Wellbore ballooning (or wellbore breathing) is a pertinent drilling issue in exploration wells where the formation lithology, geo-mechanics, pore pressure and fracture pressure regime is not fully understood. This phenomenon is generally observed in formations with micro-fractures. While the pumps are on the ECD is just sufficient to open up the natural micro-fractures allowing the mud to enter the formation. As the pumps are switched off the dynamic pressure effect is lost and the static mud weight is insufficient to keep the fracture open, resulting in the mud lost in the formation to flow-back as the fracture closes. A flow back of mud is observed on the surface with pumps off, which can be misinterpreted as wellbore influx or kick. Misinterpreting a wellbore ballooning phenomenon as a well kick can lead to the application of standard well control procedure which can aggravate the problem and may have severe implications even to the extent of well failing to meet its objective and being prematurely abandoned. This paper presents case studies of two wells, viz. NJ North East-1 and Raag Deep Main-1, drilled by the operator in the same block. Severe ballooning was observed in the first well wherein delayed identification of the phenomenon resulted in high NPT and consequential cost impact. The lessons learnt from this experience were implemented in the second well with similar ballooning issues, along with close real-time well monitoring while drilling resulting in smooth drilling operation and successful achievement of objectives as per plan This paper also summarizes suitable in-field drilling practices to be adopted and implemented to mitigate wellbore ballooning, which can be a low-cost alternative to expensive technologies used to counter this phenomenon.

Abstract Downhole fluid analysis (DFA) has successfully been used to delineate reservoir connectivity and fluid properties and to understand the origins of many complexities in oil reservoirs with the Flory-Huggins-Zuo equation of state (FHZ EOS). Equilibrium asphaltene gradients strongly imply reservoir connectivity, with fluid equilibration often taking tens of millions of years. However, reservoir fluids often demonstrate complicated compositional gradients from undergoing dynamic processes such active late gas charges, biodegradation, and water washing. In this paper, a simple 1D two-component diffusive model with analytical solutions is developed for taking into account dynamic processes in oil reservoirs. Two field applications of the developed diffusive model are active gas charging and biodegradation to better understand these dynamic processes. In the first field application, an active late gas charge results in huge nonequilibrium gradients in several fluid properties including API gravity, gas/oil ratio (GOR), saturation pressures, and asphaltene content (color optical density) measured by DFA and surface laboratory analysis. Because the reservoir is not in equilibrium, these fluid property gradients cannot be modeled by the equilibrium EOS model. Thus, a diffusive model is needed to account for the large GOR gradient. The diffusive model predicts the large variations of GOR gradients successfully. The asphaltene gradient is evidently under control of convective currents induced by the gas charge. The exact nature of this process is currently under investigation. The asphaltene gradient is consistent with the predictions by the FHZ EOS with the assumption of asphaltenes locally in equilibrium with the local fluids described by the diffusive model. The second field application is biodegradation occurring at oil/water contact (OWC). Compared to the predictions of the FHZ EOS, it is observed that the upper half of the oil column follows an equilibrium asphaltene distribution well. However, a much larger asphaltene gradient is found in the lower half of the reservoir, which gives rise to a huge (8×) viscosity variation and affects production. The measured asphaltene distribution in the whole oil column can be described nicely by the diffusive model along with the FHZ EOS. The diffusion of alkanes to the OWC (where they are rapidly consumed) is a control step. The consumption of alkanes at the OWC reduces the oil volume and increases asphaltene content and viscosity. Petroleum system modeling predicts initiation of reservoir charging in the Eocene matching the diffusive times required in the FHZ EOS modeling.

Abstract Cairn India operated Ravva Field is located offshore Krishna-Godavari (KG) Basin on the east coast of India. The field was discovered in 1987 and was brought into production in 1993 from the Middle Miocene sandstones. Oil production rate reached its plateau of ~50,000 bopd by 1999. The field produced at the plateau rate for ~ 9 years before starting to decline by the end of 2007. Two infill drilling campaigns were planned and executed in 2007 and 2011 to arrest the production decline and add incremental reserves to the field. New infill wells increased production for a short while but failed to arrest the prevailing declining trend. By the end of 2013, Ravva oil production dropped to ~21,000 bopd and was declining by 35–40% per year. Arresting the production decline by finding additional reserves in a mature waterflooded field which had already achieved ~49% oil recovery was a challenge with significant risks. Planning for additional infill drilling targeting areas of undrained oil required an integrated approach with adoption of advanced technologies to minimize risks. A 4-D monitor seismic survey was acquired in 2010 over the Ravva field and co-processed with a vintage baseline survey to identify areas of undrained oil. Separate processing of the 2010 high density 3-D survey provided improved seismic imaging of the subsurface architecture. A high resolution 3-D model was created by using sequence stratigraphic concepts, fault seal analysis studies, detailed property modeling through integration of seismic attributes, log and core data. An integrated subsurface study was initiated in 2011 to identify infill well opportunities in the field. A full cycle of integrated reservoir modeling from seismic to simulation was carried out using advanced technologies and workflows. The integrated study resulted in the identification of several infill opportunities as well as near field exploration and appraisal targets. The Ravva Phase-5 drilling campaign executed in 2014-15 comprising 8 infill, 1 water injector, and 2 exploration/appraisal wells was the most extensive infill campaign in the field's history. Well results from the drilling campaign have been very encouraging. The ten producers drilled in the campaign together added ~18,000 bopd to the field production and they are estimated to improve the field oil recovery by ~3%. By March 2015, when all new wells were brought online, Ravva field production had once again reached 28,000 bopd. The success in near field exploration and appraisal has extended the producing field boundary and has identified upsides that could support future drilling campaigns. The Ravva Phase-5 drilling campaign has showcased the first successful application of a 4-D OBC seismic project in India. New technologies such as 4-D seismic combined with integrated subsurface reservoir modeling can demonstrably arrest production decline in comparable mature oil fields and drive recovery factors closer to the technical limit.

Abstract An appraisal well in the KG Onshore Block (a joint venture of Cairn India Ltd and ONGC) has provided key engineering and operational learning's. The objective of this well was to appraise two separate low permeability reservoirs (~ 0.1md) which are ~4300m deep and falls under HPHT conditions. Due to their low permeability; hydraulic fracturing was necessary to verify the production potential of these reservoirs. To cater this, the discovery well was re-designed and sidetracked so that it could handle the expected fracturing loads. Hydraulic fractures (~387,000 lbs of Proppant); biggest in terms of proppant placed in any single stage in India, were executed and then the well was completed with slim-hole selective completion in challenging underbalanced conditions to test these reservoirs selectively. This paper primarily talks about the key constraints while planning and designing this well and then deals in detail on the learnings while executing this unique completion operation. Details on the fracturing design were already covered by Barasia et al. in SPE-171421-MS. The paper concludes with production results and the key reasons which led to ~7 fold increase with respect to previous appraisal well, as observed while production testing.

Interpreting seismic amplitudes requires an understanding of seismic acquisition and processing as well as modelling for describing and evaluating acoustic behaviour. Separate books have been written about each of these subjects and there is certainly more to say on these issues than can be presented here. The aim of this chapter is to provide a framework of basic information which the interpreter requires in order to start the process of seismic amplitude interpretation.