|Theme||Visible||Selectable||Appearance||Zoom Range (now: 0)|
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)
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.
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.
Development of the Kashagan field is very complicated and encounters many challenges, such as a harsh offshore environment with an ice season, highly pressurized wells and a high H2S concentration (sour). All these challenges were known during the field construction phase, but after one year of production, another unforeseen challenge emerged– severe downhole scaling in certain oil producers, flowing at very low water cuts (<0.5% water).
Scaling is a widespread and well-known phenomenon in many, often mature fields around the world, but it was not expected to occur in Kashagan in the early stage of field life. Well scaling developed very fast, leading to almost 50% productivity reduction on several wells in a few weeks time. Wellbore scaling put Kashagan production plans at risk, so it was critical to remediate the affected wells as soon as possible. A multi-disciplinary team started work to address the issue.
For most "brown" fields, remediation of wells affected by scaling is a routine job. In the case of Kashagan, which had just started production, downhole scaling was a big challenge for various reasons. Firstly, when rapid productivity decline was observed on some wells, it was not clear what caused the impairment, and a lot of investigative work was done to identify the nature of impairment and root cause (mechanism) behind it. Secondly, scaling badly affected D-island wells, where SIMOPS well intervention capability is highly restricted. D-island is a hub for offshore processing and gas reinjection facilities, located just few hundred meters away from wells, and any well intervention requires the creation of a "yellow zone" and causes significant production deferment. Thirdly, it was clear from the beginning that remediation is a temporary measure, and that it was important to progress from "firefighting" mode to impairment prevention mode, for all wells. Despite all complexities of the task all affected wells were successfully brought back to production and, after various successful anti-scale treatments, fine-tuning of the scaling prevention process is currently ongoing.
Due to the scaling, multiple processes had to be improved, such as metering, wells testing, wells surveillance and well interventions. In the design phase of the project, a well intervention was considered as something extraordinary, and expected to happen rarely, primarily for well integrity issues, not for scaling issues. Well intervention operations became a more routine operations and have started to play a critical role in the integrated activity planning process.
This paper describes how Kashagan wells were affected by wellbore impairment and what actions were made to remediate wells and to return wells to its original productivity.
In certain wells where relatively high levels of iron are present, the use of polyacrylamide-based friction reducers (FR) for hydraulic fracturing completions can lead to poor performance and negative chemical interactions including the formation of unusual semi-solid accumulations. The accumulations, often referred to as "gummy bears" due to their rubbery texture, can form in surface and downhole equipment and can inhibit well production. This paper summarizes work performed to evaluate the performance of FRs in the presence of iron, identifies the specific causal factors for the formation of the accumulations, and provides practical solutions to mitigate the problems associated with the negative iron impact in order to improve overall well performance.
Iron can present itself during fracturing operations in different forms and from different possible sources including source water, tubulars, and within the rock formations themselves. To study the interactions between iron sources and anionic friction reducers, synthetic and field water sources were used to identify and quantify the negative effects that iron has on performance parameters for FRs and viscosifying friction reducers (VFR) such as friction reduction, viscosity development and the development of polymer accumulations. The second portion of this paper is given to identify methods to improve overall FR performance and to mitigate the risk of developing the accumulations in iron-rich environments. Field case histories are presented to support the results of this work.
Over the years, the oil and gas industry has documented many of the detrimental effects that iron can have on well completion operations. Iron sulfide scale, for example, is the result of hydrogen sulfide and iron interacting with each other and can lead to problematic issues including loss of injectivity in water injection and disposal wells, plugging of artificial lift mandrels and perforations, reduced reservoir permeability, and other mechanisms that can limit overall well production (Nasr-El-Din et al, 2001). In hydraulic fracturing operations, the presence of iron can also have negative effects on the performance of fracturing fluids. Many, if not most, of the polyacrylamide polymers used in fracturing operations are negatively charged (anionic) in nature. When positively charged ions such as calcium (Ca2+), magnesium (Mg2+), ferrous iron (Fe2+), or ferric iron (Fe3+) come into contact with the negatively charged polymer, the result is usually a reduction in the overall performance of the polymer.
Tambach, Tim J. (Shell Global Solutions International B.V.) | Fadili, Ali (Shell Global Solutions International B.V.) | Gdanski, Rick D. (Shell International Exploration and Production Inc.) | Kampman, Niko (Shell Global Solutions International B.V.) | Koot, Wouter (Shell Global Solutions International B.V.) | Snippe, Jeroen R. (Shell Global Solutions International B.V.) | de Zwart, Bert-Rik H. (Shell Global Solutions International B.V.)
Abstract The use of reactive transport modeling (RTM) is increasing in the oil and gas industry for assessing the geochemical impact (e.g. scaling and souring) of various activities, such as waterflooding for improved oil recovery (IOR) and CO2 storage. RTM is a technique that integrates fluid flow, transport of heat and solutes, and geochemical reactions. It can be used to model fluid compositional changes as well as rock mineralogical changes, caused by geochemical reactions, under flowing conditions. We use our in-house reservoir simulator (MoReS), coupled to geochemical software (PHREEQC), to carry out RTM. Simulations are based on the mixed solvent electrolyte (MSE) model from OLI Studio, a standard tool used by production chemists, enabling accurate computation of aqueous chemical reactions and partitioning of components between solid, fluid and gas phases. Over the last few years we have used RTM to make scale predictions for several waterflooding projects around the globe. In this paper we will show results from these field cases and highlight the most important findings. In brief, these are: Enabling mineral precipitation reactions in flow calculations improves the match between measured and simulated production water (PW) chemistry. Full 3D reservoir models capture different flow paths arriving/mixing near production wells, enabling an improved match between historical and simulated PW chemistry. Simplified (1D/2D) models are sufficient for predicting the magnitude of scale deposition and screening scale prediction uncertainties when little is known about reservoir connectivity (e.g. new developments). Inclusion of clay mineral cation exchange reactions significantly modifies the evolution of the injected water composition during migration through the reservoir. As a result, this impacts the reservoir deposition of scaling minerals (e.g. barite) and the scaling potential of production wells. Characterization of cation exchange properties of clay minerals in reservoirs is therefore recommended. The developed workflow, based on learnings from various projects, is now used to forecast scaling risks in new projects and supports ongoing projects in mitigating risks (e.g. selection/timing scale squeezes).
Abstract Low-vacuum scanning electron microscopy (SEM) / energy dispersive x-ray (EDX) analysis can be used to characterize the nature of inorganic scale from produced water (Method 1); routinely used to visually determine the degree, form and composition of scale particulates. Quantitative data on scale coverage can be extracted through image analysis, and morphology can indicate origins of particulates (transported scale, active scale…). Recent trends demand more detailed quantitative analysis, believed to produce more accurate / reproducible results. Such a method is automated SEM-EDX particle analysis (Method 2). This has the advantage of full automation and delivers quantitative data on scale coverage, composition, shape and size. Neither method is perfect, the first relies on experienced SEM users, is a manual method, susceptible to bias, and is often perceived as producing qualitative data, while the second method although producing large quantitative data sets, depends upon the criteria used to classify particles, and can be time consuming. Both methods were used to examine a number of filtered produced water samples. The traditional manual method provides good representative results on scale coverage, details on particulate morphology and composition, and can be undertaken in about thirty minutes per sample; it is also a simple matter to differentiate between particulate and blanket scale deposits. The second method generates superior levels of quantitative data, but results are dependent on image thresholding (for particle selection), erroneous misleading results are all too easily obtained (unless rigorously tested particle classification schemes are used), and the method can take in excess of an hour per sample. In general Method 1 should be adequate to track scale issues from produced water, which can be supplemented where desired by automated particle analysis (APA). Where APA is to be used it is recommended that an industry standard classification criterion be developed, which will increase the degree of confidence that can be applied to results, and allow direct comparison of results between laboratories.
Abstract The control of inorganic scale deposition within production wells by deployment of scale squeeze treatments is a well-established method for both onshore and offshore production wells. Over the past 25 years the science of designing and optimising these treatments has advanced significantly with a better understanding of chemical/rock interaction, more effective modelling software to design the treatments and improved analysis methods for the determination of returning residual concentrations. Scale squeeze treatments have in general been designed to treat between 6 to 12 months of water production before either the production layer or bulk produced water composition falls below minimum inhibitor concentration (MIC). In this paper examples of the process followed to design treatments for 24 months produced water for three offshore fields (North Sea, West Africa and Middle East) are outlined. Factors that have influenced the change from 12 to 24 months squeeze treatments include changing MIC values, rising operation expenditure related to subsea vs platform deployment costs and in all cases assessing total operational cost vs simply chemical costs alone. This paper presents the field treatment designs from 4 case study fields, changing MIC values based on produced water composition which impacts chemical volumes required. The balance between cost of operation to deploy the chemical treatments to subsea vs platform wells are discussed. The implication of deferred oil associated with delayed production during pumping and post squeeze well clean-up was also considered in the design process for these wells. These case studies describe squeeze treatments which in certain wells treat over 25,000,000 bbls to MIC. The paper outlines the elements of the process that should be considered/reviewed when making the decision to change from the conventional 12 months to 24 months squeeze treatment. Designs and field results from three oil producing basins, each with different cost drivers, have been used to illustrate how it is possible to maintain effective scale management through the life cycle of these production wells.
Silica scales are perhaps the most recalcitrant deposits in the water treatment industry. Silica scale control can be achieved either by silica removal or by chemical inhibitors. Our goal is the discovery, design and application of organic additives that have some effect on silica polycondensation. Most silica control strategies assume that silica behaves like any other mineral scale. However, silica is a profoundly different issue because of its distinctly different phisicochemical features from other scales. So, silica scale control presents a rather "unorthodox" task because the actual mechanisms of silica formation are either unknown or neglected. Hence, it is important to gain detailed knowledge on the two major aspects of silica chemistry: (a) the polycondensation (polymerization) of the so-called "soluble" forms of silica (ie. silicic acid), and (b) the incorporation of silicic acid onto the surface of silica particles. This paper reports results that shed light onto these aforementioned processes. Also, the inhibition efficiency is reported of a variety of polymeric additives and some combinations in retarding silica polymerization in supersaturated aqueous solutions. Finally the effect of polymeric additives on silica particle growth is discussed.
The solubility of amorphous silica is a limiting factor to the proper operation of water-dominated production processes.1 In several areas in the world, such as Texas, New Mexico, Arizona, parts of California, Hawaii, southern Europe, the Pacific Rim and Latin America, the make-up water utilized for industrial applications contains high silica concentrations (50–100 parts per million [ppm], as silicon dioxide [SiO2]). Water-soluble silica results from quartz (crystalline SiO2) dissolution from rock formations into the groundwater, which then is used as make-up water. The risk for formation and deposition of silica scale puts forth serious challenges that pose severe limitations to proper operation of water systems. Silica scale-related problems have been termed the "Gordian Knot" of chemical water treatment, highlighting the difficulty to resolve them.2 Water systems operating personnel in power plants, evaporative cooling systems, semiconductor manufacturing, boiler and geothermal systems have to monitor water silica levels (both soluble and colloidal) very carefully on a daily basis. Silica precipitation/deposition frequently is encountered in evaporative cooling systems, where salt concentrations increase through partial evaporation of the cooling water. Silica solubility in water generally is 150 ppm to 180 ppm, depending on water chemistry and temperature. This imposes severe limits on water users, leading either to operation at very low cycles of concentration and consuming enormous amounts of water, or to use of chemical water treatment techniques that prevent silica-scale formation and deposition. Silica and/or silicate deposits are particularly difficult to remove once they form. Harsh chemical cleaning (based on hydrofluoric acid) or laborious mechanical removal usually is required.3