AbstractSand production has been a critical factor regard the safety and the economics of many oil and gas fields. The first acoustic sand monitor was commissioned in 1995. Since then, a significant amount of time and money have been spent on controlling sand production.A critical factor has always been accuracy and reliability of the systems, with different approaches used to accommodate the risk and the challenges different fields present.This presentation will look back at how things were done in the beginning, what we have learned, and how things have changed. It will also cover the technical evolution since then.We will look at the challenges still to be solved, and the experience gained in the areas of sand production, sand transport and sand monitoring.The presentation will be supported by field cases.
AbstractAs it becomes necessary to drill long horizontal extended reach wells to reach out for thin oil rim reservoirs, it also has its own challenges. Usage of new technologies and their implementation in terms of cost efficiency and increased reservoir performance is the primary objective. While producing through horizontal wells there is always a possibility of breakthrough of unwanted water or gas compromising the production of oil and to some extent leaving some valuable oil reservers behind. The reason behind this is that the heel of the well produces at higher rate than the toe because toe has to overcome the frictional pressure losses due to increased pressure drop along the horizontal length of the well.To tackle this problem Inflow Control Device (ICD) was introduced which will delay the early breakthrough of water or gas. There are different designs of ICDs available in the industry which significantly delays the breakthrough. Most ICDs provide flow restriction for the produced fluid to create uniform inflow profile along the entire length of the wellbore. However, due to uncertainties in reservoir properties there might be water or gas inflow through ICD and no existing ICDs can reverse this problem undermining the optimization of oil production.This paper presents the design of Electrical Resistivity Autonomous Inflow Control Device (ER-AICD) that on a par with creating uniform inflow profile along the wellbore; it opens and closes the valve when there is oil, water or gas inflow correspondingly. The device will work on the principle of electrical resistivity of reservoir fluids, resulting in more flexibility in downhole operations and optimizing oil production as a whole.
Hussain, Sajjad (Schlumberger) | Dhaher, Karam Sulaiman (Schlumberger) | Bjoerneli, Hans Magnus (Schlumberger) | Blackburn, Jason (Schlumberger) | Monterrosa, Leida (Schlumberger) | Jakobsen, Tom (Statoil ASA) | Otto Monsen, Gisle (Statoil ASA) | Haaland, Sigurd (Statoil ASA) | Dahl, Johan (Statoil ASA) | Østensen, Ståle (Statoil ASA) | Fjelde, Kjell Kåre (University of Stavanger)
AbstractOld platforms are not well known for extended-reach drilling (ERD) operations mainly due to rig and hydraulics limitations. ERD wells demand robust rig capabilities, good hydraulics systems, and equipment reliability. In addition, the well profile, rotary steerable system (RSS), measurement-while-drilling (MWD) and logging-while-drilling (LWD) tools, surveying, and new technologies are extremely important to the success in drilling an ERD well. RSS and drillpipe selection are important factors for hydraulics optimization. Surveying techniques are also important for time saving and improved efficiency. An ERD well in the North Sea Statfjord field was kicked off in the 17 ½-in. section from the openhole cement plug through a 50-m window between the 20-in. casing shoe and 13 3/8-in. casing stump, ensuring a smooth well profile and reduced doglegs compared to the whipstock window exit. The 17 ½-in. section was drilled and landed at a 79° inclination using point-the-bit RSS technology, and the 12 ¼-in. section was drilled in two runs as planned using the point-the-bit RSS withstanding more than 550 h down hole. The 9 5/8-in. liner was run and floated successfully in the ~6000-m section. Strict adherence to surveying techniques and quality control processes proved very helpful to meet Operator technical requirements. The 8 ½-in. section was drilled and landed on top of the reservoir with an inclination decrease from 88° to 35°. New MWD technology was successfully used in drilling the 6-in. section. These latest technologies as well as employing appropriate techniques help to drill ERD wells on aged platforms like those in the Statfjord field. This paper will describe the planning and execution phases of a challenging ERD well drilled in the Statfjord field.
AbstractThe era of easy oil recovery is over. One of the ways to economically improve oil production is through Enhanced Oil Recovery (EOR) implementation especially in mature field development. Alkaline-Surfactant-Polymer (ASP) flooding is considered to be the most promising EOR choice between the chemical flooding options due to its great effectiveness as result of synergy between Alkaline, Surfactant and Polymer. The main objective of this work is to analyse the pH evolution of different alkali species (NaOH, Na2CO3 and NH3) that should be used in ASP flooding application by using PHREEQC thermodynamic database software.The work will divide the simulation into static and dynamic test. The static test will give result of pH evolution in terms of increasing alkali concentration in the brine to measure initial performance of each alkali species. The dynamic test will be used to simulate each alkali species performance in field application and involve of building a 1D reactive model that describe flow path of communication between injector and producer well in a reservoir and measures the pH evolution at the production well. This work will also use different reservoir brine and injection water composition for each test that will represent the onshore and offshore environment due to different amount of Total Dissolved Solids (TDS) of each case.Through the result of this work it is found out that in onshore NaOH will be preferred based on its performance and cost, and as for the offshore environment case, NH3 will be more preferred based on its performance and storage size. One issue to be notice for the implementation of ASP flooding in offshore that it requires the injection water to be in low salinity and that the water treatment approach is more preferred compared to pipeline construction to provide the required injection water as it is more economical.
Omosebi, O. A. (University of Oklahoma) | Sharma, M. (University of Oklahoma) | Ahmed, R. M. (University of Oklahoma) | Shah, S. N. (University of Oklahoma) | Saasen, A. (University of Stavanger) | Osisanya, S. O. (Petroleum Institute)
AbstractSignificant amount of oil and gas reserves contain CO2 and H2S. Leakage of these gases to fresh water aquifers and their escape to the surface compromises human health and safety and create unthinkable environmental hazards. Cement exposed to these acid gases degrade, thereby promoting their release through the wellbore to overlying fresh water formations and/or the environment. This study investigates how these contaminants aid the corrosion of well cement in high pressure-high temperature (HPHT) environment.Experiments were conducted under two broad test conditions. In the first case, cement cores were aged at 100°F in CO2-H2S brine solution. The total test pressure was varied from 3000 psi to 9000 psi. In the second case, cement cores were exposed to brine saturated with gas mixture comprising H2S, CO2, and CH4 at total test pressure of 6000 psi. Temperature was varied from 100°F to 350°F. The compressive strength, shear bond strength, porosity, and permeability of the aged and unaged specimens were measured to quantify the alteration in these critical cement properties. Observations are supported with FTIR, SEM and EDS analyses.As temperature increases, the presence of H2S shows more impact on the loss of mechanical strengths and increase in transport properties of Class G cement than Class H cement. Variation of H2S concentration also shows significant impact on cement integrity.Compared to previous study involving the exposure of cement to pure CO2, the presence of H2S improves the relative strength of cement. However, transport properties are compromised. FTIR mineralogy confirms that the extent to which cement is carbonated by CO2 is limited by the presence of H2S. In addition, SEM and EDX indicate that ettringite was formed at low temperature (100°F). However, it dissolves at high temperature (350°F) without significantly compromising the structural integrity of cement.The most significant new finding in this study is that the presence of H2S and its coexistence with CO2 under HPHT conditions minimizes the loss of the structural integrity of well cement by pure CO2. This is important because it narrows down the most significant factor to consider when designing acidresistant cements for HPHT wells.
York field is located in the Southern North Sea (SNS), within the UK offshore license blocks 47/2a, 47/3a, 47/3d, and 47/3e. The field lies 40 km east of the Humberside coast in a water depth of 42 m, approximately 25 km northeast of the Yorkshire coast and adjacent to the Rough Gas storage field. York field has been in production since 2012. The field consists of four production wells from a normally unmanned installation (NUI). All four wells have active downhole sand control and long horizontals drilled and completed in the reservoir section. This paper presents the design phase and execution for sand screen completions and provides an in depth process of the selection criteria for the lower completions performed in York field. Findings are presented along with analyses of the design methodology and installations to date. In addition, results of the well post-completions data are discussed.
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.
AbstractTo prove that PVT input to reservoir models is representative, the comparison between the modeling of PVT data and relevant PVT laboratory measurements should preferably be as direct as possible.A black oil reservoir simulation model can be described as a compositional model with only two hydrocarbon components (‘oil’ and ‘gas’). The reservoir fluid is represented by a set of tables, defining oil and gas viscosity and formation volume factor as a function of pressure, temperature and composition.Examples on quality assurance of fluid modeling by direct comparison of PVT input for black oil and compositional reservoir simulation with PVT laboratory measurements are shown in the present paper, including results from Differential Gas Liberation (DGL) for reservoir oil and Constant Volume Depletion (CVD) for reservoir gas.Challenges with regard to black-oil modeling of depth gradients are also discussed.
Jøssund, Tor-Ole (Aker BP) | Elfenbein, Carsten (Aker BP) | Johansen, Yngve Bolstad (Aker BP) | Drange, Ingrid Sætre (Aker BP) | Olsborg, Lodve Hugo (Aker BP) | Skorve, Torstein (Aker BP) | Kvilaas, Geir-Frode (Aker BP) | Christoffersen, Kjell (Aker BP) | Mastad, Sigbjørn (Aker BP) | Stubsjøen, Marte (Aker BP) | Wang, Haifeng (Schlumberger) | Denichou, Jean-Michel (Schlumberger) | Charef-Khodja, Hakima (Schlumberger)
AbstractThe Ivar Aasen field was discovered in 2008 and consists of two main groups of reservoirs – the Jurassic and Triassic reservoir zones. The reservoir architecture is complicated by their different depositional settings and by syn- and post-sedimentary faulting. Developing a new field of such complexity is a challenging task that demands a novel approach to optimize well placement and improve reservoir characterization.Reservoir mapping while drilling (RMWD) technology has recently been introduced to the industry, providing an array of deep, directional measurements that are converted to a resistivity map of the formation out to approximately 30 m above and below the borehole. The reservoir mapping results are available for the operator to make geosteering decisions during drilling, to optimize the completion design with inflow control devices after TD, and to update the post-well reservoir model for planning the next wells. This process helps the operator maximize the benefits from the already drilled well on the yet-to-drill wells. The sequence of the wells to be drilled can be logically arranged to leverage the maximum value from the information that reservoir mapping provides.The drilling campaign on the Ivar Aasen field started in summer 2015 and the RMWD technology was used while drilling all the production wells. It revealed that the actual reservoir structure was even more complex than originally expected, and enabled the operator to pursue the best well path to maximize field production potential. This was achieved by using the data to actively geosteer, estimate reservoir producibility (through permeability-thickness calculation) in real-time to decide on TD, and by sidetracking to new targets revealed by the mapping. This new approach can also be applied to infill campaigns on existing fields. In this paper, one of the producer wells are reviewed in details to illustrate the process and demonstrate the results.
Varne, T. (ALTUS Intervention) | Jorgensen, E. (ALTUS Intervention) | Gjertsen, J. (ALTUS Intervention) | Osugo, L. (Qinterra Technologies) | Friedberg, R. (Island Offshore) | Halvorsen, E. C. (TechnipFMC)
AbstractThis paper describes the approach, experience and results achieved by a North Sea operator (the Operator) when using purpose-built riserless light well intervention (RLWI) vessels to perform continuous well intervention operations on its subsea fields over the last 10 years. Using RLWI vessels on a continuous basis, the Operator has been able to; achieve a high intervention intensity on its subsea wells (345% increase—from 11 wells in 2006 to 49 wells in 2016), lower the intervention cost per well and improve field recovery factors. The contributory factors to these successes that are covered in this paper are: –Continuous improvements in efficiency during all stages of the intervention operation. This has resulted in the capacity to perform more interventions and hence a lower intervention cost per well. Specifically, over the last 10 years, there has been a 60% decrease in the average number of days to perform an operation.–Improved reservoir management, as a result of regular data acquisition of production and saturation monitoring logs.–Introduction of new technologies and the improved robustness of powered mechanical intervention systems. This has enabled more complex intervention work scopes, such as milling and manipulation of completion components, which would previously have required a modular offshore drilling unit (MODU).The next target, is to reach water depths deeper than 1500 m. Some of the main challenges and equipment upgrades required to work at these depths are discussed.