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Zhang, Ke (Rice University) | Chanpura, Rajesh A. (Schlumberger) | Mondal, Somnath (University of Texas at Austin) | Wu, Chu-Hsiang (University of Texas at Austin) | Sharma, Mukul M. (University of Texas at Austin) | Ayoub, Joseph A. (Schlumberger) | Parlar, Mehmet (Schlumberger)
Particle size distribution (PSD) is used for various purposes in sand control: decision between various sand control techniques (e.g., Tiffin criteria), sizing of the filter media (sand screens and/or gravel packs) through either rules of thumb (Coberly, 1937; Saucier, 1974; etc.) or physical experiments or theoretical models (Chanpura et al., 2012, 2013; Somnath et al., 2011, 2012). PSD of formation sand samples are also often used to generate “simulated” formation sand for laboratory experiments. Two most commonly used techniques for PSD measurements are sieve and laser, while some engineers use one technique for no obvious or justifiable reasons, others use both techniques for measurements and don’t know what to do with the data when significant differences exist in PSDs obtained from each technique. Although the inherent limitations of, and the differences between, these two techniques as well as other factors impacting the measurements are well known, a systematic study as to what is relevant to sand control along with when and why is lacking. In this paper, we critically review the current practices in PSD determination and use and misuse of the information obtained from those measurements, propose a methodology towards determination of what is relevant, when and why, and present our initial experimental results that support our conclusions.
Vasheghani Farahani, Mehrdad (Sharif University of Technology) | Soleimani, Rasa (Sharif University of Technology) | Jamshidi, Saeid (Sharif University of Technology) | Salehi, Saeed (University of Louisiana at Lafayette)
The effects of drilling fluid’s filtrate on formation damage have been plaguing the industry. Drastic decrease in production due to the damage in the pay zone has been reported in several occasions. This often is associated with uncertainties to predict filtrate invasion and lack of proper mud engineering design.
Invasion of solids and filtrate can be reduced to an acceptable level by the formation of low permeable filter cake. During the filtration process, particles of certain sizes bridge the formation pores and establish a base on which the filter cake can form. Particles considerably smaller than the pore opening may invade the formation. In addition, knowledge of the mudcake characteristics such as thickness, solid contents and also filtration rate of mud filtrate will help the drilling engineer to stay on good conditions especially during drilling pay zones.
Factors affecting filtration process are time, temperature and pressure. In this paper, an advanced analytical model and related laboratory experiments (Figure 1) are presented. The mathematical model estimates mudcake thickness and filtration radius in both static and dynamic conditions with consideration a radial system at constant temperature conditions. The mudcake thickness and permeability variation with time are also considered in the dynamic model.
Second, the results of the simulation will be compared with experimental data in order to verify the simulation results. And, finally, filtrate invasion under high pressure and high temperature are analyzed by digital images (Figure 2) and SEM where potential recommendations are made.
Fluid flow through oil and gas reservoirs can induce movement of parts of the rock within and through the pore network. This movement or “fines migration” can have a significant impact on well and reservoir performance. Laboratory testing and detailed mineralogical study can help with quantification and qualification of the potential for and impact of fines migration.
Laboratory core flood testing can be used to try to predict the potential for fines migration in any fluid phase and at any velocity. The design of the tests and the limitations of such testing need to be considered before data is too rigidly employed. Ideally, tests should be conducted with the same fluids as will be present in the reservoir, under the same temperature and pressure conditions (including consideration of depletion) and the flow rates carefully selected to replicate reservoir velocities. If tests are conducted carefully then various conclusions on the impact of fines migration on well and reservoir behaviour can be drawn. Several new cases will be presented that demonstrate the potential use of good data and the danger in badly designed tests.
Definition of the size, shape and composition of mobile fines is important in order to understand the potential impact of the fines. Quantification of potential mobile fines is useful but data must be carefully analysed. High fines content is an indication of potential fines migration damage risk but is by no means a definitive predictor. Instead, mineralogical identification needs to be coupled with physical flow testing in order to identify the risk.
If good quality data is acquired the risk of fines migration damage or excessive fines production can be identified and in some cases, appropriate mitigation against fines migration can be adopted. Several cases from oil and gas production wells and water injection wells will be used to illustrate best practice and identify the consequences of inadequate testing.
An Operator was unable to model a potential recompletion of a 330 m cased hole perforated sand screen interval in a mature high water cut well which was originally completed with a 916 m open hole stand alone sand screen and Inflow Control Devices section in a multidarcy sand.
The potential opportunity to perforate this 330 m section presented significant potential reservoir drainage upside but could not be modelled using conventional well inflow prediction or reservoir simulation techniques. In order to determine if the recompletion was economically viable, the operator required a way to model the recompletion and the existing completion to determine the overall completion performance.
The complexity of the original open hole section completed with sand screens and ICDs and the new target to be completed with perforations, sand screens and ICDs was solved using computational fluid dynamics modelling and high performance computing.
The existing and new reservoir intervals are characterised by unconsolidated high permeability sands. The reservoir conditions mobility ratio of oil to water is approximately 30:1. Due to high total liquid production rates, the existing wellbore is producing at well above the economic oil rate cut off despite being at approximately 95% water cut and therefore the existing completion interval cannot be abandoned. The new recompletion perforation interval would initially produce at 100% oil. The key question was, what will the new recompletion interval add (if anything) to the overall well production rates and is the new recompletion economically viable. Conventional analytical or even 1D or 2D numerical models simply cannot handle the complexity of the geometry of this well’s open and potential cased hole intervals, perforated intervals, sand screens and ICDs.A 3D fully coupled well model was constructed and 2 phase CFD modelling undertaken in a combined model size of over 500 million cells each with unique properties. Through employment of what is thought to be the most comprehensive inflow model ever built, the contribution from the original and new wellbore were estimated and optimum completion design enabled allowing the operator to determine the economic viability of the recompletion.
With gas production from gas condensate reservoirs, the flowing bottomhole pressure of the production well decreases. When the flowing bottomhole pressure becomes less than the dew point pressure, condensate accumulates near the wellbore area and forms a condensate bank. This results in loss of productivity of both gas and condensate. This becomes more serious in intermediate permeability gas-condensate reservoirs where the condensate bank reduces both the gas permeability and the well productivity.
Several techniques have been used to mitigate this problem. These methods include: gas cycling, drilling horizontal wells, hydraulic fracturing, injection of super critical CO2, use of solvents and the use of wettability alteration chemicals. Gas cycling aims to keep the pressure of the reservoir above the dew point pressure to reduce the condensation phenomena. The limited volumes of gas that can be recycled in the reservoir can hinder the application of this method. In order for an ideal recycle, gas volume injected into the reservoir will be larger than the total gas that can be produced from such a reservoir. Other approaches are drilling horizontal wells and hydraulic fracturing where the pressure drop around the wellbore area is lowered to allow for a longer production time with only single phase gas flow to the wellbore. These approaches are costly as they require drilling rigs. Another technique is the use of solvents which shows good treatment outcomes, but the durability is a questionable issue in these treatments. Moreover, wettability alteration needs to be approached very carefully as to not cause permanent damages to the reservoir. It was reported in many studies the use of fluorinated polymers and surfactants dissolved in alcohol-based solvents for wettability alterations treatments.
Each method has its own advantages and disadvantages, and can be applied under certain conditions. The paper presents all of these methods along with their advantages and disadvantages, besides description of some of their field applications and case studies.
The Viking formation in southern Saskatchewan Canada represents an active area where steep production declines in the first year of production are common and are often attributed to near wellbore or reservoir deposition of paraffin. Decline rates of 50-60% in the first year on production have been observed.
Traditionally, extended paraffin protection in the wellbore is the targeted area for solid paraffin inhibition programs. Treatments are evaluated on their ability to delay the need for conventional liquid chemical applications in the wellbore or flow lines. In this study, solid paraffin inhibitors were used to target paraffin deposition in the reservoir, to delay production declines. This area is beyond the reach of conventional treatments. Low formation temperatures, cloud points, and higher asphaltene content are common Viking characteristics that promote paraffin precipitation. The solid paraffin inhibitors are used to stabilize the paraffin in the initial stages of the well life, when deposition is predicted to be most severe.
The chemical additive treatment was designed through product selection testing using cold finger deposition tests, compatibility testing with the fluid system, and crush prediction models. A baseline of the untreated oil characteristics was determined using offset wells. Pour point, carbon number distribution and asphaltene percentage were analyzed in each well. The solid inhibitor application effectively prevented conductivity restrictions due to paraffin deposition issues in the reservoir.
Placement of solid paraffin inhibitors into the Viking formation with the proppant during hydraulic fracturing increased cumulative production by approximately forty percent per well in the first 350 days on production and reduced decline rates. The comparison of 150 untreated wells completed in 2010 to 2012 with the 90 wells treated with the solid paraffin inhibitor has increased reserves estimates by fifty percent. Wells drilled in the same area, with similar frac systems, depths, horizontal lengths and stages are compared.
The results of matrix stimulation in carbonate formation strongly depend on the acid injection condition. Large amounts of lab tests indicate that an optimum acid interstitial velocity, v i-opt, exists, which results in the minimum volume of acid required for wormhole propagation (optimal breakthrough pore volume) and the most efficient stimulation. During the last decade, much progress has been made to identify the factors that affect the optimum conditions of linear coreflood experiments, including temperature, acid type, acid concentration and lithology. However, there lacks a discussion on the effect of core dimensions on the optimal conditions. Experimental results published before show strong evidence that the optimal condition changes as the dimension of core samples changes.
For many decades, chelating agents have been used successfully as additive in the oil and gas industry, for example during scale removal, iron control and matrix stimulation. More recently, these chemicals have also been used as standalone fluids for the same applications. However, the traditional chelating agents like ethylene diamino tetraacetic acid (EDTA), hydroxyethyl ethylene diamino triacetic acid (HEDTA) and nitrile triacetic acid (NTA) suffer from slow biodegradability and/or an unfavorable health profile. To better meet the stricter health, safety and environmental requirements of the regulatory bodies and the industry, new environmentally friendly chelating agents have been introduced. The question is whether these new chelating agents have the required properties for a versatile downhole application. This paper compares four commercially available, readily biodegradable amino polycarboxylic acid type chelating agents on a number of properties relevant for the oil and gas industry. It covers solubility and compatibility experiments, corrosion tests with low-carbon steel and Cr-based alloys and coreflood experiments on both carbonate and sandstone cores. The corrosion and coreflood experiments were conducted under realistic temperature and pressure conditions. Finally, attention will also be paid to the health, safety and environmental profile of the chelating agents. Although the structural resemblance of the
tested chelates is great, the results proof that even the slightest change in the chemical structure can have a significant impact on the properties and hence the use in the oil and gas industry. Furthermore, the results show that
the new generation of chelating agents include candidates that have a lot more to offer than the traditional chelates in terms of corrosion, functionality in matrix acidizing jobs, descaling, impact on tubulars, completion, and environment.
Copyright 2014, Society of Petroleum Engineers This paper was prepared for presentation at the SPE International Symposium and Exhibition on Formation Damage Control held in Lafayette, Louisiana, USA, 26-28 February 2014. This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of SPE copyright. Abstract A drilling and completion program was developed for a two-rig deepwater completion campaign in West Africa that included openhole water injectors and oil producers drilled in a highly unconsolidated sandstone reservoir with permeability that ranged from several Darcy to tens of Darcies. The limited storage onshore and discharge options mandated recycling fluids from well to well. For the expanded sand screen application, the 8½-in. Wellbore stability required the drill-in fluid to be at least 10.8 lb/gal to control the shale and avoid hole eccentricity. Fluid rheology was critical as circulating density could not exceed 12.3 lb/gal to stay below the predicted 12.5-lb/gal fracture gradient, and good hole cleaning was essential in the horizontal sections that reached out to 1,000 m. When running the screen, particulates in the mud had to pass through the 150-µm mesh otherwise the screen would plug and ultimately collapse. To attain the required weight, the screen-running fluid utilized fine micron-grind barite to attain density while avoiding screen plugging. The well was then displaced to completion brine. Reducing cross contamination during these displacements was important to avoid costly disposal. The unique chemistry and properties of these systems demanded a comprehensive fluid management and quality control plan that began with product procurement, through the warehouse and mixing plant, onboard the supply vessels that stored these fluids, and final transfer and use on the rigs. Avoiding cross contamination and preservation of each of the different fluid for each successive well was crucial to minimize damage to the target sand, reduce rig time, and to reduce overall cost. Water depth is approximately 3,100 ft (945 m). Gascondensate was discovered in 2007 and subsequent appraisal wells confirmed crude oil and a water leg down-dip of the discovery well.
Sand and fines production is one of the oldest problems in petroleum industry and one of the toughest to solve. Today, many active and passive technologies and methods exist; in some cases some sand and fines production is manageable, while for others it cannot be tolerated at all. Also, many wells do not produce sand or fines from the onset and may not require an active sand control solution until later in their live. Chemical sand control solutions have been around for many years have always been attractive due to their ability to be installed without any restrictions to the well bore geometry. However, due to the difficulties with placement and in many cases their association with some degree of reduction in permeability there has been some reservation to use chemical methods as a standard. This paper presents a unique chemistry that not only increases the maximum sand/fines free rate without a significant reduction in permeability, but also discusses the advanced placement techniques essential for a successful application. This paper includes study of two hundred and fifty wells which has been treated by using zeta potential altering chemistry and shows analysis of both failed and successful applications and the lessons learned.