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Abstract Pigging of Once Through Steam Generators (OTSGs) indicated various types of scales, the most predominant of these being silicates of hardness causing ions. It was noted that scaling propensity can potentially go up with higher Steam Quality (SQ) as the reject stream gets concentrated with ions. However, models suggested that there are benefits of higher SQ in enhancing fuel savings (8%) and electricity savings (2%) when SQ was increased by 20%. The challenges of higher SQ were noted in terms of increased scaling tendency and therefore the need for improved softening. In Field D, the service cycle, the backwash cycle, and the brining cycle were optimized leading to a gain in throughput and reduction in salt consumption. Service cycle improvement gained 30 % to 130 % in throughput between two regenerations, backwash cycle improvement by fluidizing the bed to nearly 35% helped gain 10% in throughput, and reduction of brining cycle from 75 minutes to 48 minutes helped reduce salt consumption by 56% without impacting the throughput. In Field B, a six month pilot revealed that shallow shell resins where ion-exchange is more efficient due to inert core (better intra particle diffusion control) can enhance the throughput by 30% - 80% and simultaneously reduce the number of regenerations by 15 – 30%. Resin fouling is still a major challenge to contend with as oil can foul the resin and throughput can decline by 0.5 – 3 folds. In a plant operation, where there are multiple softener and brine vessels, there is a need to optimize them as a system. Reliability, Availability, and Maintainability (RAM) Models are used in Field C to a) Address equipment configuration optimization with impact on capital capacity expansion project scope b) Understand how net softwater delivery capacity was affected by increases in inlet hardness and c) Assess through a comparison scenario, if the large cost of addressing the valve issue in an upstream nutshell filter was worth the lost production opportunity related to unplanned downtime.
Abstract A cold flow plant consists of a Water Management System (WMS) for separation and treatment of produced water, and a Wax Control System (WCS) for making solid wax particles that can travel through the long tieback line without further deposition on the pipe wall. Pre-conditioning to a level of 1-2% remaining water implies that avoidance of hydrate formation can be handled by reasonable volumes and traditional chemical methods. The Wax Control System enable a temperature independent transport of oil dominated flows by continuous removal of deposited wax from the pipe wall, allowing the solid wax particles to travel with the flow in the export line without any risk of further deposition of wax along the export pipeline. The technical qualification work included design and operation of a Pigging Loop that allowed continuously removal / handling of wax within a bundled pipeline.
Abstract Oilfield scales are crystalline minerals made up of Na, K, Mg, Ca, Ba, Sr, Fe, Cl from produced water that can precipitate out in the reservoir, well, pipelines and process during the production and transportation of oil and gas. These precipitates can deposit as a result of thermodynamic and/or chemical changes and pose costly flow assurance issues to the oil industry. Several factors have been identified to be responsible including temperature, pressure, ionic strength, pH, evaporation, bicarbonate anion, super-saturation and contact time and water chemistry. Attempts to solve this problem in the past have focused mainly on the use of chemical inhibitors and the most accepted mechanism of scale inhibition is squeeze injection method. While adsorption and retention of scale inhibitors on rock formations needs more research, there had been improvement to better ways of ensuring adsorption and precipitation through nanotechnology including the use of nano-carbon enhanced squeeze treatment (NCEST). The uses of these conventional inhibitors have been found to be toxic to the flora and fauna in biotic communities during water disposal. In order to reduce the environmental burden caused by these conventional solutions and still manage the problem effectively, greener solutions have been proposed. This review x-rays the mechanisms of scale precipitation and deposition, evaluate the solutions that have been provided in literature based on efficiency, economics and environmental impact and propose guidelines to field operators in selecting optimum solutions.
The article presents a brief description of the Samaraneftegas’s software for determining the precipitation of calcium carbonate and sulphate, the formation of iron sulphide when mixing different types of water with each other and predictive rationing of the quality of wastewater when injected into reservoirs. The article highlights the features of computer programs for engineering calculation methods and the scope of their application in problems for various technological processes of oil and gas production. The calculation program for the assessment of salt deposition in the determination of calcium carbonate (CaCO3) takes into account the dependence of all constants on mineralization, in the determination of calcium sulphate (CaSO4) uses three methods: with strict conditions, averaged and taking into account elevated temperature and magnesium ions. The Iron Sulphide Precipitation Assessment (FeS) program takes into account the excess of one component over another (H2S and Fe). The program for rationing water quality for flooding takes into account a unique base of a reference sample of values of indirect search signs for recognizing the type of reservoir of an oil deposit. The choice of the reservoir type with engineering calculations of the stability and compatibility of reservoir waters using computational programs that take into account the unique properties and high mineralization of the waters of the deposits of the Volga-Ural region allows choosing the optimal strategy for organizing the system of oil collection, oil treatment, reservoir pressure maintenance and waste water disposal at all stages of the design and operation of oilfield facilities. The programs are also suitable for use in the selection of well silencing fluid and the prevention of salt deposits in the process of oil production.
Gundogar, Asli S. (SLAC National Accelerator Laboratory / Stanford University Energy Resources Engineering) | Druhan, Jennifer L. (University of Illinois at Urbana) | Ross, Cynthia M. (Stanford University Energy Resources Engineering) | Jew, Adam D. (SLAC National Accelerator Laboratory) | Bargar, John R. (SLAC National Accelerator Laboratory) | Kovscek, Anthony R. (Stanford University Energy Resources Engineering)
Abstract Field and laboratory observations to date indicate that the efficiency of hydraulic fracturing, as it relates to hydrocarbon recovery, depends significantly on geochemical alterations to rock surfaces that diminish accessibility by partial or total plugging of the pore and fracture networks. This is caused by mineral scale deposition such as coating of fracture surfaces with precipitates, particle migration, and/or crack closure due to dissolution under stress. In reactive flow-through experiments, mineral reactions in response to acidic fluid injection significantly reduced system porosity and core permeability. The present study focuses on changes to fluid chemistry and shale surfaces (inlet and fracture walls) resulting from shale-fluid interactions and integrating these findings for an improved estimate of transport-related consequences. The reacted shale surfaces were examined by spatially-resolved scanning electron microscopy - energy dispersive spectroscopy (SEM-EDS) analysis. Importantly, inductively coupled plasma - mass spectrometry/optical emission spectroscopy (ICP-MS/OES) was utilized to probe the chemical evolution of the core-flood effluents. The three study cores selected from the Marcellus formation represent different mineralogies and structural features. In flow-through experiments, lab-generated brine and HCl-based fracture fluid (pH=2) were injected sequentially under effective stress (up to 500 psi) at reservoir temperature (80°C). SEM-EDS results confirmed by the ICP concentration trends showed significant Fe hydroxide precipitates in clay- and pyrite-rich outcrop samples due to partial oxidation of Fe-bearing phases in the case of intrusion of low salinity water-based fluids. Porosity reduction in the MSEEL (Marcellus Shale Energy and Environmental Laboratory) carbonate-rich sample is related to compaction of cores under stress due to matrix softening with substantial dissolution, and pore-filling by hydroxides, as well as barite and salts. Despite the same fluid compositions and experimental conditions used for both MSEEL samples, barite precipitation was much more intense in the MSEEL clay-rich sample due to its greater sorption capacity and additional sulfate source as well as fissile nature with multiple lengthwise cracks. ICP tests revealed time-resolved concentration trends in produced brine and reactive fluids that in turn complemented the pre-/post-reaction SEM-EDS observations.
Abstract Although scaling is common in both conventional and unconventional oil and gas wells, inflow scaling has not been studied in depth for unconventional environments. This paper presents a multi-disciplinary and nimble scientific approach proved to be effective in managing the discovery of scale in Point Pleasant wells in the Appalachian basin. The methodology included characterization of the scale (type/source identification, quantification and prediction) with development of methods for production surveillance and remediation. Utilizing a variety of solid sample testing, chemistry modeling, and investigative techniques, a strong basis of understanding was developed about the type, envelopes, and mechanisms of scale formation. Thermodynamic scale modeling coupled with tornado plots was used to identify key variables and then simplify into envelope plots for use in prediction and surveillance as input to key operational decisions. An in-house reservoir tool was developed as an adaptation of the Rose Plot, to quickly identify inflow impairment that is automated in a visualization tool and does not require bottom-hole pressure gauges. Remediation treatments with acid were applied to target both inflow and outflow regions of a well. Post-remediation production results from the squeeze treatments were within 200 Mscfd of the prediction for two of the treatment wells. The study confirmed scale existed in the lateral and possibly in the near-wellbore area (e.g. the perforations) of all three wells and proved an economical remediation technique for the inflow portion of a well, via 2 conveyance methods (tubing vs coil). Introduction Scale deposition in oil and gas wells is an age-old flow assurance problem in the Exploration & Production industry – where there are hydrocarbons and water there is likely to be scale (Morris, 1937). There are two primary types of scales - organic and inorganic. Organic scales are hydrocarbon-based and include deposits such as wax and asphaltenes. Inorganic scales are mineral deposits that can occur naturally based on produced water compositions, or when formation water mixes with different brines such as hydraulic frac water. The diversity of dissolved ions in formation water coupled with changes in the state of the reservoir fluids over time through production or addition of hydraulic frac fluids, may result in precipitation of carbonate, sulfate, sulfide and halite mineral scales (Rao, 2017).
Offshore oil and gas fields exist along the continental shelf of every continent--even Antarctica. Commercial fields are in operation offshore Africa, Asia, Australia, North America, and South America. Documented offshore production activities began in 1896 from a pier in Santa Barbara County, California. Today, offshore production facilities may be located hundreds of kilometers from land, in water depths approaching 10 000 m. Offshore wells may be platform based or subsea. Expected well productive life may be as short as 10 years or greater than 50 years.
Koksalan, Tamer (ADNOC Onshore) | Ahsan, Syed Asif (ADNOC Onshore) | Azouq, Youcef (ADNOC Upstream) | Alhouqani, Shamsa Sulaiman (ADNOC Onshore) | Al Blooshi, Ahmad (ADNOC Upstream) | Ali Basioni, Mahmoud (ADNOC Upstream)
Abstract Oil leakage, due to well integrity issues of varying proportions, from downhole completions is a common phenomenon despite all measures and adherence to regulations. These leakages potentially could cause environmental damage through surface spill, aquifer contamination and in worst-case scenario loss of human lives. In an offshore setting, impact of well integrity issue can be more severe than in an onshore well due to complex and often costly offshore well operations. Downhole completions including cement quality deterioration occurs with the passage of time due primarily to corrosive nature of hydrocarbons produced from a well. Oil companies perform routine well integrity surveillance by acquiring real time annulus pressure data, cement bond, temperature and sonic logs to assess well integrity and perform remedial measures, if and when, required. Leakage may also occur in a complex pattern from nearby wells and different reservoir than the suspected reservoir and show up in the annulus or eventually on the surface. Whilst, well integrity surveillance data indicates leakage when it occurs, finding the exact source location of leakage is often difficult. Objective of this study was to perform a cost-optimized reservoir to annulus leakage oil correlation using geochemical methods in an offshore well to establish the source of oil in the annulus.
Abstract Asphaltens presence in the reservoir fluid has great implications on downhole as well as surface facilities. These problems are not only related to production impact, but also significant integrity as well as surface facilities operational challenges are seen to affect the upstream oil and gas production facilities. Handling the asphaltenes rich fluid brings inherent challenges with it starting from well bore to the production facilities. Adequate engineering solutions need to be integrated into the design of production facilities as well as wellhead equipment which would greatly enhance production efficiency while successfully facing asphaltens challenges. The nature of asphaltens as well as their growth rate are not very well understood due to their complex chemistry with different hydrocarbons. Therefore there will not be a 100% success while managing the asphaltens, however these proactive steps would upto great extent would reduce the downtime and other asphaltene related impacts. This paper presents an effective way to address asphaltenes challenges as faced by surface and subsurface facilities in oil and gas production operations. Best industry practices for mitigating asphaltenes related challenges, which not only sustained the production but also enhanced asset integrity performance, have been presented for experience sharing and enhancing the asphaltenes handling capability. The reservoirs with asphaltenes presence are quite difficult to handle and maintain due to complicated nature of asphaltens, which result into various problems with downhole as well as surface facilities. These problems result into scales blockage of well bore and flow lines thus causing blocked flow and in most of the cases complete seizure of wells fluid flow.