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Bentonite is not typically used as the primary fluid-loss agent in normal-density slurries. In low-density slurries, where higher concentrations can be used, it may provide sufficient fluid-loss control (400 to 700 cm 3 /30 min) for safe placement in noncritical well applications. Fluid-loss control, obtained through the use of bentonite, is achieved by the reduction of filter-cake permeability by pore-throat bridging. Microsilica imparts a degree of fluid-loss control to cement slurries because of its small particle size of less than 5 microns. The small particles reduce the pore-throat volume within the cement matrix through a tighter packing arrangement, resulting in a reduction of filter-cake permeability.
Pasqualette, M. A. (ISDB FlowTech) | Carneiro, J. N. E. (ISDB FlowTech) | Ribeiro, G. G. (ESSS) | Soprana, A. B. (ESSS) | Girardi, V. (ESSS) | Bassani, G. S. (Repsol Sinopec Brasil) | Merino-Garcia, D. (Repsol)
Since the path between the reservoir to the surface facilities is long and with a broad range of pressures and temperatures, it is almost certain that the fluids (gas, crude oil and water) will be within a hydrate formation region during the field lifetime (23). It can be in a normal producing condition, which is avoided most of the time using insulation or injection of inhibitors, or during a well shutdown/restart, which would require other techniques, such as fluid replacement and heating (25). In any case, hydrate prevention and management methods can add significant CAPEX or OPEX costs to the project and minimizing them can be of utmost importance to a safe and profitable operation. In that light, alternative production methods, like cold-flow (10), intend to produce hydrocarbons within the hydrate stability region expecting that they will be formed, but its crystals would only be transported without significant agglomeration and deposition and thus, will not block the pipeline. However, to guarantee such operation, not only a very reliable simulation model has to be used in the design phase, but it is also important to have a monitoring system that can foresee and advise the possibility of a pipeline blockage due to unexpected conditions.
Abstract Five different variants of the acrylamidotertiary-butyl sulfonic acid (ATBS) / N,N-dimethylacrylamide (NNDMA) copolymer were examined and evaluated, comparing their mixability and fluid-loss performance. These were characterized using gel permeation chromatography equipped with multi-angle laser light scattering (GPC-MALLS) and viscometry to evaluate the effects of number average molecular weight (Mn), radius of gyration (Rg), dispersity (Đ), and viscosity values in water and cement. It was determined that there was an optimum Đ value at which the mixability performance of the cement slurry formulated with the fluid loss copolymer was achieved. Additionally, it was determined that an increase in Đ improved fluid loss performance for a given Mn and Rg. More interestingly, an increase in Rg at fixed Mn and Đ decreases fluid-loss performance, which is counterintuitive to the particle bridging mechanism. A quantitative relationship between the copolymer characteristics and its fluid-loss performance was determined. Understanding the relationship between structure and function of 2-acrylamido-2-methylpropane sulfonic acid-NNDMA copolymers in a cement slurry is the first step toward designing fluid-loss additives with targeted properties.
This work provides a new method to directly predict the effect of hydrate formation on transient flow in oil & gas flowlines. The method couples established models for transient flow, fluid properties, and hydrate formation to allow for prediction of the severity of hydrate formation in transient operations and rapid exploration of a large parameter space for design considerations.
As subsea oil and gas production moves to deeper water, the increasing reservoir and transit pressure and lower seafloor temperature increase the driving force for gas hydrate formation. Overcoming such large driving forces using the conventional strategy of thermodynamic hydrate inhibitor (THI) injection may be economically limiting because the volumes of THI required become prohibitively expensive . This reality has motivated a paradigm shift toward hydrate management, wherein the ability for hydrate particles to cause a blockage is limited as a result of the operating strategy or the injection of low dosage hydrate inhibitors (LDHIs) . The successful application of this new approach requires the application of rigorous multiphase flow models that are capable of coupling hydrodynamic flow descriptions with fundamental descriptions of hydrate growth rate and particle transportability. Traditional simulation strategies have isolated hydrodynamic predictions from hydrate-specific calculations, precluding a direct coupling of both phenomena when describing the pipeline pressure network. Instead, heuristics for hydrate modules such as CSM-HyK OLGA have been developed that allow coarse estimation of hydrate blockage severity in oil-continuous flowlines, based primarily around the maximum apparent viscosity of the hydrate-in-oil slurry . While such approaches have provided an ability to even attempt the modelling of hydrate blockage formation in pipelines, the next generation of these predictive tools must directly integrate hydrate-specific formation and transportability models within a transient multiphase flow algorithm. In this manuscript, we present the first attempt at such a direct coupling, and illustrate the application of this approach to an example case study.
Summary This work presents a new simple algorithm for the rapid screening of hydrate plug formation risk, using experimental models of gas hydrate plug formation in oil-dominant systems. The algorithm is based on hydrate formation from an emulsified water phase, where resultant hydrate particles may interact to form large aggregates that increase slurry viscosity and pressure drop. Predictions of pressure drop were compared with a hydrate-forming industrial flow loop, resulting in average absolute deviations between model and experiment of less than 5 psi for liquid-phase Reynolds numbers of less than 75,000 and water content below 70 vol% of all liquid.
Summary Polymeric viscosifiers are added to cement slurries for a variety of reasons, including prevention of particle settling and control of fluid loss, gas migration, and free water. Many of these functions are critically important after the cement slurry has been placed behind the casing but before the setting of the cement. Some functions, such as particle-settling prevention, are also important during the pumping phase. Unfortunately, most of the viscosifying polymers suffer from thermal thinning at bottomhole temperatures, especially under shear. The amount of polymer required to maintain the required level of viscosity at elevated bottomhole temperatures causes excessive surface-slurry viscosification at ambient temperature. Pumping such slurries can require higher pump pressures, which, in some cases, might exceed formation breakdown pressures causing unintended fractures.This becomes a serious challenge when the window between the fracture pressure and the pore pressure of the formation is narrow. It would be a significant improvement to oilfield cementing technology to develop polymers that do not cause excessive slurry viscosification on the surface but gradually increase the slurry viscosity as it reaches downhole temperatures, with the maximum viscosity reached at the time the slurry becomes static behind the casing. This paper describes a chemical method, not based on encapsulation, for modifying biopolymers and their derivatives—for example, hydroxyethylcellulose (HEC) and xanthan—that renders them insoluble in cement slurries at room temperature (RT). When the cement slurries containing modified HEC are heated, the slurries develop viscosity upon heating, as reflected by changes to slurry rheology with temperature. The method also provides for increased viscosification efficiency of the modified polymers because of the increased molecular weights of the modified biopolymer products. Synthesis details, slurry rheologies at different temperatures, and job-placement simulation details are presented. A possible reaction mechanism that is operative in the chemical-modification step is also discussed.
Abstract Polymeric viscosifiers are added to cement slurries for a variety of reasons, including prevention of particle settling and control of fluid loss, gas migration, and free-water. Many of these functions are critically important after the cement slurry has been placed behind the casing but before the setting of the cement. Some functions, such as particle-settling prevention, are also important during the pumping phase. Unfortunately, most of the viscosifying polymers suffer from thermal thinning at bottomhole temperatures, especially under shear. The amount of polymer required to maintain the required level of viscosity at elevated bottomhole temperatures causes excessive surface-slurry viscosification at ambient temperature. Pumping such slurries can require higher pump pressures, or in cases where formation breakdown pressure might be exceeded. This becomes a serious challenge when the window between the fracture pressure and the pore pressure of the formation is narrow. It would be a significant improvement to oilfield cementing technology to develop polymers that do not cause excessive slurry viscosification on the surface but gradually increase the slurry viscosity as it reaches downhole temperatures, with the maximum viscosity reached at the time the slurry becomes static behind the casing. This paper describes an economical chemical method, not based on encapsulation, for modifying biopolymers and their derivatives—for example, hydroxyethylcellulose, xanthan, and guar—that renders them insoluble in cement slurries at room temperature (RT). When the cement slurries are heated, the slurries develop viscosity, as reflected by rheological measurements. The method also provides for increased viscosification efficiency of the modified polymers because of the increased molecular weights of the modified biopolymer products. Synthesis details, slurry rheologies at different temperatures, and job-placement simulation details are presented. A possible reaction mechanism that is operative in the chemical-modification step is also discussed.
Abstract Flow Assurance is a major challenge in offshore and deepwater operations. The current approach is based on preventing/delaying gas hydrate formation by using thermodynamic inhibitors (methanol, etc) and/or kinetic hydrate inhibitors and/or operating outside the hydrate stability zone by pipeline insulation and/or active heating. The above techniques are not economical and in some cases practical for deepwater operations, long tiebacks, and ageing reservoirs (i.e., high water cut). The industry needs new and novel techniques to tackle Flow Assurance in these challenging conditions. The approach presented in this communication, i.e., Hydraflow, is based on gas hydrates management, instead of prevention. HYDRAFLOW concept is based on allowing gas hydrate formation but preventing their agglomeration and pipeline blockage. The idea is to convert most or all of the gas phase into hydrates and transfer them in the form of hydrate slurry in the pipeline. Where produced water is limiting factor for hydrate formation, excess water (e.g. seawater) can be added. It is also possible to adjust the hydrate slurries viscosity by adjusting the amount of water. Anti-agglomerants and other additives might be necessary to control the hydrate crystal size and prevent solid blockage in these systems. Where possible, it is proposed to use a " Loop?? concept which allows circulating the liquid phase (totally or partially) and its associated additives. The recycled fluid acts as carrier fluid, transferring produced hydrocarbons to their destination (e.g. platform). In this case, all or part of the additives including anti-agglomerants (AAs) can be recycled, hence reducing the operational costs and potential environmental impact. This paper presents the latest results of development of the HYDRAFLOW technology, including hydrate growth and kinetic for different systems (low and high GOR) and effect of salts (e.g. from reservoir brines or added seawater). Introduction Progressively, oil and gas production and transportation are extending to deeper water, mature fields and long tiebacks. These conditions, which involve low temperatures combined with high pressures, high water cuts and longer transfer times, are well inside hydrate risk zone and a major challenge in deep water field development to ensure unimpeded flow of hydrocarbons. It also means that existing flow assurance techniques - which have limitations on preventing hydrate formation - are becoming less practical and economic. Therefore, the industry needs new and improved ways of tackling this problem. This has resulted in the introduction of novel techniques where hydrates are not prevented, but managed to prevent their agglomeration and pipeline blockage. These techniques are generally regarded as cold flow, which have several common characteristics, including,no heating or insulation, hydrates are not prevented but allowed to form and their agglomeration is avoided by various techniques. Several research groups are working on various cold flow concepts, most notably SINTEF-BP (Wolden et al., 2005, Larsen et al., 2001, Lund et al., 2000) and NTNU (Gudmundsson, 2002). IFP has also studied hydrate slurries in flowing conditions and particularly in multiphase flow lines (Peysson et al., 2003). CSIRO/IFP are also investigating hydrate transport in continuous gas phase.
Abstract Flow Assurance continues to remain a major challenge in offshore production operations. Current methods for avoiding gas hydrate problems are generally based on one or a combination of the following three techniques:injection of thermodynamic inhibitors (e.g. methanol, ethylene glycol) to prevent hydrate formation, use of kinetic hydrate inhibitors (KHIs) to sufficiently delay hydrate nucleation/growth, and maintaining pipeline operating conditions outside the hydrate stability zone by insulation and/or active heating and/or by controlling pressure.1 However, for many production operations, particularly deepwater fields, those requiring long tiebacks, and mature reservoirs (where water cuts can be very high), the above techniques may not be economical and/or logistically practical. Thus the industry needs novel and improved techniques to tackle flow assurance problems for such challenging conditions. The new approach presented in this paper -HYDRAFLOW- aims to meet this need. HYDRAFLOW is a novel 'cold flow' concept, which breaks from the tradition of straightforward hydrate prevention. Instead, gas hydrate formation in pipelines is intentionally induced and managed, eliminating the need for expensive thermal/chemical inhibition while improving the economics and practicalities of multiphase fluid transport. Experimental analyses of low and high GOR systems for various different production scenarios with and without AA (Anti-agglomerant) have been undertaken as part of HYDRAFLOW concept development. The effect of simulated shut-in on fluid transportability has also been tested. A new experimental set-up for measuring the viscosity of the fluid system under high-pressure conditions has been designed and commissioned in order to evaluate the rheology of the systems under investigation. Results prove that the concept is viable (at least under laboratory conditions), and strongly suggest that HYDRAFLOW technology could offer significant benefits over existing flow assurance strategies, providing a novel low CAPEX/OPEX solution for challenging (e.g. deepwater, long tie-backs, mature fields) operations. Introduction Generally, most of the existing gas hydrate flow assurance techniques are based on avoiding solid hydrate formation. This is normally achieved by either reducing water content, reducing heat loss to the environment (e.g. by insulation and/or active heating) or the injection of thermodynamic and/or kinetic hydrate inhibitors. However, all of these approaches have limitations, particularly in the case of deepwater operations, high water cuts (e.g. mature fields) and/or long tieback systems. As forecasted by ITI Energy, global oil and gas production is increasingly being dominated by exploitation of mature fields, meaning existing techniques - which are more geared to new developments (lower water cuts) - are becoming less practical/economic.2 Thus the requirement for alternative strategies is expected to continue to increase in the future. HYDRAFLOW is a new, patented flow assurance technology, which aims to meet this need. The concept of HYDRAFLOW is to be able to transport oil/gas without any thermal (i.e. insulation or active heating) or high dosage chemical treatment, thus greatly reducing the costs of multiphase hydrocarbon pipeline transport. The absence of thermal and/or major chemical treatment means HYDRAFLOW falls under the umbrella of 'cold flow' technologies.
Abstract Compared with conventional tubing fracturing, coiled tubing (CT) fracturing has several advantages. CT fracturing has become an effective stimulation technique for multi-zone oil and gas wells. CT fracturing is also attractive production enhancement method for multi-seam coalbed methane wells as well as wells with bypassed zones. The excessive frictional pressure loss through CT has been a concern for CT fracturing. CT strings have small diameter and this limits the cross-sectional area open to flow. Furthermore, the tubing curvature causes secondary flow and hence results in extra flow resistance. This increased friction pressure results in high surface pumping pressure. The maximum possible pump rate and sand concentration, therefore, have to be reduced. To properly design a CT fracturing job, it is, therefore, essential to be able to predict the frictional pressure loss through CT accurately. This paper presents two correlations for the prediction of frictional pressure of fracturing slurries in coiled tubing. One is developed based on full-scale slurry flow tests with 1–1/2-in. coiled tubing and slurries prepared with 35 lb/Mgal guar gel. The extensive experiments were conducted at the full-scale coiled tubing flow test facility. The other correlation is derived from the Srinivasan's friction factor correlation of Newtonian fluid in coiled pipes. The Srinivasan correlation is modified for the non-Newtonian fluids and it further requires an inclusion of the relative slurry viscosities which have been thoroughly evaluated in this study. The proposed correlations have been verified with the experimental data and actual field CT fracturing data. Case studies of wells recently fractured using CT are provided to demonstrate the application of the correlations. The correlations will be useful to the CT engineers in their hydraulics design calculations. Introduction Hydraulic fracturing through coiled tubing (CT) has become an effective stimulation technique for multi-zone oil and gas wells.- Hydraulic fracturing via CT is also an attractive production enhancement technique for mutely-seam coalbed methane wells. In CT hydraulic fracturing, proppant such as sand is conveyed through the continuous string of coiled tubing as transport conduit to the fracture in a formation. Compared with conventional tubing conveyed hydraulic fracturing, CT hydraulic fracturing has a number of advantages. In particular, CT provides the ability to quickly move in and out of the hole (or be quickly repositioned) when fracturing multiple zones in a single well. CT also provides the ability to fracture or accurately spot the treatment fluid to ensure complete coverage of the zones of interest when used in conjunction with appropriate bottomhole assembly tools such as straddle packers. This is particularly important for stimulation of multiple zones or bypassed zones or horizontal wellbores. At the end of the formation treating operation, CT can be used to remove any sand plugs used in the treating process, and to lift the well to be placed on production. The excessive frictional pressure loss through CT has been a concern for CT fracturing operations. CT strings have small tubing diameter - small enough so that adequate tubing length can be spooled onto the coiled tubing reel. This limits the cross-sectional area open to flow. Furthermore, the tubing curvature causes secondary flow and hence results in extra flow resistance. Therefore, fluid frictional pressure losses in CT hydraulic fracturing are much higher than those associated with conventional tubing fracturing. This increased friction pressure results in much higher surface pressure at the injection rates required for hydraulic fracturing. This elevated surface pressure is one of the dominant factors that currently limit the application of coiled tubing fracturing. High surface pressure necessarily implies that fluid injection rates will have to be much smaller when compared to conventional fracturing and the maximum sand concentration has to be reduced since sand increases slurry fluid friction pressure. To properly design a CT hydraulic fracturing job, it is therefore essential to understand the flow behavior of hydraulic fracturing slurry in coiled tubing string and be able to predict frictional pressure loss in CT accurately.