AbstractA well was completed in April 2014 and put online a day after completion. However, it was shut-in shortly after due to a production trip. Massive sand production (2 000 pounds per thousand barrels) was observed during the restart of the well. Sand free production could not be achieved by performing multiple choke reductions. The sand shut-off intervention failed and distributed acoustic sensing indicated multiple sand entry points along the wellbore.A concentric coiled tubing (CCT) sand vacuuming operation was planned to be performed in order to clean out the well and reinstate production. A previously used conventional sand cyclone, and flowback system for CCT cleanout operations, needed to be replaced. This large unit had low separation efficiency resulting in excessive amounts of solids being transported to the process facilities. For a higher separation efficiency, this original unit was replaced by a compact (200cm x 200cm footprint) patented dual vessel desander, a passive design with no internal motor, and a stackable filter unit.The system was first put into operation during a CCT sand vacuuming intervention to reinstate the production from the well. The use of the system resulted in major cost savings due to the introduction of a less complex surface solids removal system, and majorly reduced footprint, giving a reduced rig up/rig down time and improved HSE. In addition, the system resulted in increased operational efficiency due to the 100% removal of solids from the flow stream.This paper describes a CCT sand cleanout operation where a dual vessel non-motorized desander, with a stackable filter unit, was used and discusses a case study presenting operational considerations, system description and results of the operation.
AbstractA coiled tubing (CT) campaign was executed on the Skjold field in the Danish sector of the North Sea in 2014. One of the objectives of this campaign was to perform production logging in horizontal oil producer wells, located in a highly fractured chalk reservoir. Most of these wells are unable to flow without artificial lift due to the high water cut and low reservoir pressure. Stable flow for logging was achieved by combining CT operations with a surface Liquid Jet Compressor (LJC). The campaign was successful in acquiring both production (PLT) and spectral noise logging (SNL) data.The SNL tool complemented conventional PLT as it provided information on quality of zonal isolation, vital in planning of water shut off and/or re-stimulation activities.Well A was completed with a gas lift valve straddle which had to be retrieved to gain access to the wellbore for production logging. Retrieving the straddle disabled access to lift gas, which meant the well was unable to produce. Liquid jet compressor technology in combination with nitrogen lifting through CT was implemented to allow steady fluid flow for logging.The surface liquid jet compressor (LJC) lowered the production system backpressure seen by the well from 500 psig to 0. Together with the continuous nitrogen pumping through CT, stable well flow was achieved and the logging program was successfully executed. The results were used to identify fluid flow behind casing, water producing zones and to identify sub-optimally producing oil zones for re-stimulation. Using the LJC significantly reduced the total nitrogen volume required by 60%. This was crucial as limited crane capacity and deck space presented additional logistical and operational challenges. In order to overcome these, equipment had to be rigged up on a bridge connecting two platforms with the CT reel lifted in three spools and welded on location. This in turn required the fiber optic cable to be injected on-site offshore.The novel combination of a surface LJC with nitrogen lifting via CT reduced the number of crane lifts, load outs, nitrogen transfers and overall cost. Furthermore, it improved operational efficiency and job safety.Ultimately, this combined concept enabled successful acquisition of the required data.
AbstractThis paper aims to discuss completion of deepwater open-hole gas wells that were completed using an alternate paths system (APS) and a state-of-the-art viscoelastic surfactant (VES) carrier fluid. The wells presented multiple design and operational complexities such as high bottomhole temperature, narrow fracturing window, extended horizontal laterals, and unstable shale zones. Operational and design steps considered to overcome these complexities are discussed, making this literature a resource that maps obstacles and presents viable solutions faced in any similar operation. These complexities combined with deepwater operational requirements and economics made cost of failure unacceptable.Two 8.5-in. openhole depleted gas wells up to bottomhole temperature of 230 °F were completed with gravel pack treatments using a VES carrier fluid to counter sand settling, minimize friction pressures, and optimize fluid viscosity. The operations pumped 200% excess proppant compared to design volume to ensure complete packs downhole, countering any thief zones or open-hole washout regions. Returns were taken through the BOP via mud line to avoiding high fluid friction in the choke line. In one case, the riser was displaced with lighter base oil to reduce the bottomhole pressures.Using the alternate path system and VES carrier fluid proved to be highly successful in these wells, as compared to the pre-drilled liners and standalone screens used previously in the same field. Complete packs were obtained within narrow fracture gradient windows in all cases. After reversing out the slurry, a filter cake dissolver treatment was also performed to decrease the flow initiation pressure for the well. Case studies have been presented elaborating completions plan and execution of open hole gravel pack treatment for two 8.5-in wells.This literature is a case study elaborating operational procedures that have proved to be successful in performing open-hole gravel packs under complex constraints. This paper serves as a reference, highlighting obstacles faced and presenting viable solutions for any similar operation.
SummaryThis paper develops a new von Mises ellipse based on backup pressure (internal pressure for collapse and external pressure for burst), so the new API collapse equations with dependence on internal pressure can be shown simultaneously on the same plot with the ellipse. Unlike the current ellipse used for casing and tubing design which is approximate, the new ellipse is exact for collapse, burst, and axial loads. Without the new ellipse, the approximate ellipse will continue to be used, and the new API collapse equations must be plotted separately. Example cases demonstrate the advantages of the new ellipse, including increased accuracy. Results help clarify many questions about the new API collapse equations, namely where they come from and how to use them.
AbstractToday's practice on the Norwegian Continental Shelf when designing solutions for permanent plug and abandonment (P&A) complies with NORSOK Standard D-010. This is a prescriptive approach to P&A, as opposed to a "fit for purpose" risk-based approach. A risk-based approach means that any given P&A solution is expressed in terms of the leakage risk, which can be formulated in terms of the following quantities; the probability that the (permanent) barrier system will fail in a given time period and the corresponding consequence in terms of leakage to the environment.As a part of building a leakage risk model for permanently plugged and abandoned wells, a simple leakage rate calculator has been developed for quick evaluation of the leakage potential from a given (permanent) well barrier solution. The leakage potential from the well can then be quantitatively assessed taking into account different leakage pathways including leakage through bulk cement, through cement cracks and through micro-annuli along cement interfaces.In the paper, we will provide models to estimate leakage rate for each leakage pathway and show how to integrate them in an overall leakage calculator, to obtain a description of leakage flow from the reservoir through failed barriers to the environment. The information and input parameters needed to achieve this will be discussed, and uncertain parameters will be treated probabilistically, thus allowing for expressing uncertainty in the leakage rate estimate.Results from the leakage calculator will be demonstrated on a synthetic case, showing variants of a permanently plugged and abandoned well.
El Boubsi, Rachid (Huisman) | Andresen, Jan Atle (Huisman) | van Og, Geertjan (Huisman) | Bjørkevoll, Knut S. (SINTEF Petroleum) | Nybo, Roar (SINTEF Petroleum) | Brevik, Jan Ove (Statoil) | Nygaard, Gerhard (Cybernetic Drilling Technologies) | Smith, George G. (Intelligent Mud Solutions)
AbstractManaged pressure drilling (MPD) is an adaptive and sophisticated drilling process used to control the downhole and annular pressure. Mud management could enhance MPD as the downhole pressure is dependent on mud parameters such as mud density and rheology. Therefore, a step-change is needed in drilling process control, to enable consistently high performance, accurate pressure control and reduced risk of unwanted effects. Advances in process control have been made, but risk reduction and optimization of the drilling process is still a major challenge in the drilling industry.A missing piece in considering the process-control puzzle is the in-situ determined drilling mud characteristics. Without accurate knowledge of mud properties and cuttings contents or without an ability to adjust the mud in real-time, a control system cannot reliably maintain bottom hole pressure or ensure a smooth flow of cuttings. The use of real-time density and rheology measurements in combination with a model that optimize the drilling operation by adjusting the mud will be a radically new innovation on the drilling market.To complete the puzzle, a demonstration of a pilot unit will be carried out. The unit combines monitoring of mud and cuttings with wellbore hydraulic modelling and a control system that adjusts mud properties in real-time. The control setup will strive to keep the drilling operation within its operating envelope with respect to cuttings transport and bottomhole pressure. The demo project will construct such a system from existing components. Its focus will be on demonstrating the potential of a fully integrated drilling system. In particular to demonstrate that mud properties can be adjusted automatically based on real-time mud measurements. This demonstration project will be carried out in collaboration between Huisman, Statoil, SINTEF, Intelligent Mud Solutions (IMS) and Cybernetic Drilling Technology (CDT), with financial support from the Norwegian Research Council.The demonstration project will take place at Huisman Innovative Tower in the Netherlands, where a full scale facility with drilling rig and a 400 m deep test well goes operational in Q1 2017. Available technology from the project partners covers many of the process control components. Such as a commercial hydraulic flow model for downhole pressure predictions provided by SINTEF, a mud density and rheology sensors provided by IMS with software by CDT and a mud treatment system of Huisman's design, allowing for real-time adjustment of mud.
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.
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.
AbstractLaboratory experiment is the main tool for determining fluid properties such as saturation pressure, formation volume factor, fluid density and viscosity. However, both sampling and experiments are limited by cost and time. On the other hand, the information about the fluid properties are essential for reservoir engineering works such as reserves and productivity calculation. Therefore, empirical correlations are commonly used as an alternative method.Researchers developed empirical correlations by curve-fitting experimental data. The variation in the correlations is partly due to different datasets. It explains why each correlation more accurately estimates the fluid properties in some cases/regions than in the other cases/regions.In this study, we propose a technique of using surrogate models and the available laboratory database to estimate the fluid properties. Two surrogate models are studied in this paper e.g. universal kriging and neural networks. A comparative analysis is being performed between the proposed technique and known correlations used in the industry. The study shows that the proposed method demonstrates better estimation than the published empirical correlations.This paper has a potential to become a guideline for engineers who would develop an estimation tool with the use of experimental fluid database.
AbstractStoring captured CO2 within the under ground aquifers to reduced CO2 emission could serve the safe long term storage option. However, operation costs a lot. While, injection of CO2 within the natural gas hydrate reservoirs which is associated with CH4 production could compensate the cost of CO2 storage. Besides production of CH4 from natural gas hydrate reservoirs causes the de-stability of gas producing area which leads to land slides and geological hazards in the area. However, as a result of stable CO2 hydrate formation, combining the CO2 storage with CH4 production could hold the structural stability of the production areas. In this work, we used a reactive transport simulator to model injection of CO2 within the intact methane hydrate reservoir. Our model showed the CO2 hydrate formation within the gas hydrate areas.