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Altemeemi, Bashayer (KOC) | Gonzalez, Fabio A (BP Kuwait) | Gonzalez, Doris L (BP America) | Jassim, Sara (KOC) | Snasiri, Fatemah (KOC) | Al-Nasheet, Anwar (KOC) | Al-Mansour, Yousef (KOC) | Ali, Abdullah (NAPESCO) | Sheikh, Bilal (NAPESCO)
Asphaltenes flow in equilibrium with the liquid phase as other components of the produced hydrocarbon. If asphaltenes are in solution during production, there are not negative impact to well productivity. However, asphaltenes could precipitate as pressure, temperature and composition change. If precipitated, due to pressure decrease, asphaltene could deposit as a solid phase in the formation rock near wellbore becoming an obstruction to flow and inducing formation damage. Skin due to asphaltene deposition near wellbore was confirmed in several wells of a carbonate reservoir. Asphaltene deposition was also observed in the production tubing. The objective of this work is to investigate the main variables affecting asphaltene deposition in the Magwa-Marrat field is South East Kuwait and develop a technique to manage and/or decrease formation damage due to this solid deposition phenomena. In order to estimate the skin value and predict the location of any impairment to production, a pressure gauge was set at 1,000 ft above the top of the perforations and the well was equipped with a permanent multiphase meter device. A series of pressure buildup tests and multi-rate tests were run to disseminate Darcy skin from non-Darcy skin. Pressure transient analysis (PTA) delivered total abnormal pressure losses from the formation near wellbore to the gauge location, while multi-rate tests (MRT) allowed to investigate rate dependent skin. Well tests at different rates were also run to investigate the relationship between fluid velocity and asphaltene deposition. Once the elements of total skin were split into Darcy skin and Non-Darcy skin, a tubing clean-out and a stimulation job were designed and implemented to eliminate the asphaltene deposits and remove the damage. Total skin was reduced from +30 to −3.5 and productivity index was increased by a factor greater than ten (10). The production rate to mitigate asphaltene deposition was successfully determined. The well has been on production for about 1 year without developing any additional damage and without further deposition of asphaltene in the production tubing as the well has been flown above the minimum flow velocity that would allow asphaltene deposition. A combination of well intervention combined with determination of operating conditions have been developed to successfully produced asphaltenic hydrocarbons at flowing bottom hole pressure (FBHP) below asphaltene onset pressure (AOP). This methodology has been successfully implemented. If the liquid velocity is high enough to carry precipitated asphaltene out, solid deposits are not observed and there is not harm to productivity. The technique has worked for a case where reservoir pressure has been depleted below asphaltene onset pressure (AOP). This is a fundamental change in the globally applied industry approach that urges to produce asphaltenic hydrocarbons at FBHP above AOP.
In this study we estimated the initial effective fracture pore volume (Vfi) and fracture volume loss (dVef) for 21 wells completed in the Montney and Eagle Ford formations. We also evaluated the relationship between dVef and choke size. First, we applied rate-decline analysis to water-flowback data of candidate wells to estimate the ultimate water recovery volume, approximated as Vfi. Second, we estimated dVef using a fracture compressibility relationship to evaluate the fracture volume loss of the Eagle Ford wells. Third, we investigated the effect of choke size on dVef for the Eagle Ford fastback and slowback wells.
Semilog plots of flowback water rate vs. cumulative water volume show straight-line trends, representing a harmonic decline. The estimated Vfi accounts for approximately 84 and 26% of the total injected water volume (TIV) of the Montney and Eagle Ford wells, respectively. The results show that approximately 10% of the fracture volume is lost during flowback. This loss in fracture volume predominantly happens during the early flowback and becomes minimal during the late flowback period. The results show a relatively higher dVef for fastback (a flowback process with a relatively large choke size) wells compared with that for slowback (a flowback process with a relatively small choke size) wells. In this study we proposed a method to estimate the initial fracture volume and investigated the loss in fracture volume during the flowback process. Analyses of the field data led to an improved understanding of the factors that control water flowback and the effective fracture volume.
Muqtadir, A. (King Fahd University of Petroleum & Minerals) | Elkatatny, S. M. (King Fahd University of Petroleum & Minerals) | Mahmoud, M. A. (King Fahd University of Petroleum & Minerals) | Abdulraheem, A. (King Fahd University of Petroleum & Minerals) | Gomaa, A. (BP America)
ABSTRACT: Hydraulic fracturing is an integral part of geomechanics and is employed to improve the productivity from unconventional reservoirs. It is performed by injecting fracturing fluid at high pressures to induce fractures in the formation. Reservoir conditions and petrophysical properties differ from formation to formation further requiring to optimize the design of the fracturing process. This paper aims to address one such issue by quantifying the reduction in breakdown pressure because of saturation condition of the reservoir. An experimental study is performed on tight sandstone rocks by using a robust setup. Fracturing fluid is injected into tight sandstone samples by means of a central hole until fracture is induced. Samples were saturated by brine and reservoir oil. Based on the experimental results, Significant reduction in the breakdown pressure of brine saturated samples was seen and moderate reduction in the oil saturated samples as compared with dry cores. This was confirmed by comparing with UCS and Brazilian tensile tests.
Hydrocarbon reservoirs with low permeability and porosity often require to be treated to produce economically. Hydraulic fracturing is usually performed in such reservoirs. Fracturing fluids are pumped into the borehole and pressurized in order to induce a fracture in the rock formation. These fluids are carefully designed to perform fracturing. Even though this process is being carried out since decades, some challenges still need to be addressed. Because of the drilling activities, the fluid saturations in the near wellbore area may change causing variability in the breakdown pressure. This paper aims to quantify the reduction in breakdown pressure caused by change in saturation.
The strength of the rock is said to be reduced as fluid enters into its pores. Substantial work has been conducted in the past to quantify this effect using unconfined compressive strength test (UCS), ultrasonic velocity measurements and Brazilian tensile tests. A general reduction is seen in the UCS and the Young's modulus of most kinds of rocks like sandstone, carbonate, shale and even for volcanic rocks(Brignoli et al., 1995; DeVilbiss, 1984; Hawkins and McConnell, 1992; Henao et al., 2017; Labuz and Berger, 1991; Lashkaripour and Ajalloeian, 2000; Perera et al., 2011; Vasarhelyi, 2003; Widarsono et al., 2001; Wong et al., 2016; Yagiz and Rostami, 2012; Yu and Nasr-El-Din, 2009; Zhang et al., 2017)
It is well known that dry abrasive blasting cannot remove salts completely and therefore, some residual salts remain on the blasted steel surface. In offshore or coastal corrosive environments, it is difficult to keep the near white metal finish and control salt on the prepared surface until coating application. The bare steel can flash rust in a couple of hours. There are several commercial cleaning products to remove residual salts and to extend the surface cleanliness time. Three types of grit blasted steel surface preparation methods were performed; (1) blasted new steel to SP-10, (2) blasted pre-rusted steel to SP-10, and (3) blasted pre-rusted steel to SP-10 + cleaned with the salt removal chemical. The purpose of this study is to compare the coating performance on these three types of surface preparations. Three types of tests were conducted; rust creepage, cathodic disbondment and water immersion tests. Three different coating systems for atmospheric service and three different coating systems for immersion service were used in this study. The test results indicate that a small amount of residual salts have a detrimental impact on coating performance.
It is a common practice to use dry abrasive blasting to clean steel surfaces before maintenance coating application. In offshore or coastal corrosive environments, blasted (dry and wet) steel surfaces become flash rusted within a couple of hours. It is difficult to keep the desired near white metal finish. Soluble salts on the surface cause premature coating breakdown and could drastically reduce the coating life. There are several commercial cleaning chemicals to remove residual salts and to extend the surface cleanliness time.
Salts are thought to be one of the major causes of premature coating breakdown. Soluble salts are ionic chemical compounds that dissolve in water to form ions. The ions form an ionic bond to the carbon steel. Even with high pressure water washing or abrasive blasting, some of the bonded ions are difficult to remove. A combination of mechanical and chemical removal is usually required. Some common ions of a salt that affect coating performance are chloride, nitrate and sulfate.
There is a significant use of Nickel based alloys in the oil and gas industry for high strength / high corrosion resistance applications, yet there has been a lack of understanding of fracture toughness of these Ni alloys under seawater / Cathodic Protection (CP) environments. Furthermore, this class of alloys has demonstrated a weakness following high profile failures where the failing mechanism identified was Hydrogen Assisted Cracking (HAC). This study examines several Precipitation Hardened (PH) Nickel alloys by the J-R Curve method (ASTM E1820) using side-grooved single edged notched bend (SENB) fatigue pre-cracked test samples in a simulated seawater environment under CP. The Ni alloys evaluated, a good representation of those associated with the in-service failures reported in the past, were UNS N07718, UNS N07716 and UNS N07725 together with other alloys, more recently developed, such as UNS N09945 and UNS N09955.
The materials were tested in a 3.5%NaCl solution with applied potentials of −1.1V and −1.4V vs SCE at room temperature at a loading rate of 0.005 Nmm−3/2. The overall response of the alloys in laboratory air was elastic-plastic in nature while the behavior in environment shifted towards a linear-elastic response most likely associated with the embrittlement caused by the hydrogen adsorbed during CP. Scanning electron microscopy analysis was performed to obtain insights on the fracture morphologies. Amongst the alloys tested, UNS N07718 showed the least reduction in fracture toughness in the environment in relation to air while alloy UNS N07716 and N07725 showed the most susceptibility to the environment with the lowest performance.
The Oil and Gas industry has turned to Nickel alloys, especially precipitation hardened (PH) Nickel alloys, for subsea applications where high strength, high corrosion resistance, as well as cracking resistance are needed to be sufficiently operational in these applications. These Ni alloys are mainly but not only utilized where newer wells are encountering pressures above 15,000 psi and temperatures above 350°F.
Although Nickel alloys are needed for these high pressure high temperature (HPHT) applications, there have been known field failures with PH Ni alloys, such as UNS N077181-4. Many of these field failures have been linked to specific microstructural features. In particular, the presence of sufficient amounts of delta phase precipitation at the grain boundaries leads to intergranular cracking in UNS N07718 materials. Thus, although high strength makes these nickel alloys attractive, it may also make them more susceptible to hydrogen embrittlement.
Precipitation Hardened (PH) nickel alloys have been used extensively and successfully in the Oil & Gas Industry for many years. These materials offer high strength and outstanding corrosion resistance in many aggressive environments and they are a common selection for high-strength equipment for downhole, wellhead, subsea and Christmas tree applications. However, several high-profile failures have occurred, including tubing hangers, cross-overs and subsea bolts with alloys such as UNS N07718, UNS N07716 and UNS N07725. In all these cases, the mechanism identified was Hydrogen Assisted Cracking (HAC) as a result of embrittlement from atomic hydrogen absorbed by the alloy in specific operating environments.
PH nickel alloys exhibit complex microstructures with multiple potential secondary and tertiary phases. They require carefully controlled thermomechanical processing and heat treatment to deliver performance that is adequate for the intended applications If processed improperly (particularly during hot working and heat treatment), the resultant microstructure may adversely affect the material properties and suitability for the intended service. Despite the number of scientific and technical contributions produced over the last years, the interaction between these complex microstructural features, the service environment and atomic hydrogen is still not well established. This is further complicated by variations in testing approach used to study and simulate hydrogen charging conditions. The present paper provides insights on the HAC failure mechanism for API 6ACRA PH nickel alloys comparing findings from numerous studies. In addition, implications for currently adopted standards and emerging specifications are also presented and discussed.
UNSa N07718 has been employed by the aerospace industry for hot turbine sections since the 1960’s. This material was adopted by the oil and gas industry in the 60’s and 70’s to deliver a high strength material option for increasingly hot and high pressure wells. The adoption while largely successful, did have early failures between the late 90’s and the early 00’s due to Hydrogen Assisted Cracking (HAC). Lessons learned from such failures, which will be reviewed in the following sections, resulted in manufacturers and operators coming together to create APIb Specification 6A7185 which better ensured HAC-resistance by close control of microstructure and all influencing process steps. For example, chemistry is restricted to make the most likely deleterious phase (δ phase) less likely, and metallographic assessment assures that the phases present (including δ phase) are not distributed deleteriously (by avoiding continuous, or semi-continuous grain boundary networks and avoiding the most damaging form of delta phase - acicular platelets).
Polymer liners, especially polyethylene liners are commonly used in carbon steel lined pipe for water injection service. Historical seawater/produced water applications have a typical design temperature of 60°C or less and are usually operated from 30 to 40°C. Handling of oilfield water, in the operating temperature range between 60°C to 90°C becomes a challenge. Very limited applications have been reported at elevated temperature and details of specific operational conditions are not known to validate safe and reliable performance at high temperatures.
This paper explores the current state of the art for the increased temperature limits of high density polyethylene liners and identifies the most credible failure modes to be mitigated. A testing campaign was conducted on commercial grade high density polyethylene to de-risk the application of the liners to operating temperatures up to 80°C. A series of small scale testing were performed to understand the material properties under different conditions (temperature, oil saturation, oil/water concentration etc.).
Performance properties of typical high-density polyethylene were benchmarked against a proposed raised temperature polyethylene grade. The material properties were used as an input to a finite element analysis tool to evaluate the strains experienced by the liner at various locations such as a weld bead, flange connection and vent location. The testing and analysis provides increased confidence to expand the operational envelope of polyethylene liners to higher temperatures in produced water service. A condition monitoring plan has been developed to record the liner condition during operation.
While the pipeline industry has wide experience handling produced water, it is often proven to be cumbersome due to the corrosivity of the fluids to carbon steel or costly when CRA (corrosion resistant alloy) are selected. Industry wise, plastic lined carbon steel pipeline have been widely adopted for onshore water handling, mostly in Canada where only low concentrations of gas are present in the produced and source water. In Alberta, there are almost 7900 km of lined steel pipelines, according to a report by the local regulator (Alberta Energy Regulator, 2013). Of that inventory, 4700 km is in water service, equating to a quarter of all water pipelines. The remainder of plastic liners are mostly in multiphase service.
Thermal insulation is used in operating facilities to conserve heat and protect against freezing amongst others. A consequence of insulating the equipment is the necessity to manage the introduced threat of corrosion under insulation (CUI). For CUI to occur, water and oxygen must enter and migrate through the insulation to reach the external surface of the equipment. The water transport characteristics are dependent on several factors such as type of insulation, type of jacketing, equipment operating temperature, external weather, water entry/leakage rate and cyclic service. In hot piping, there are competing water transport characteristics, as in water vapor moves outwards away from the equipment as water enters insulation. Knowing the water transport and the parameters that influence the time of wetness at the metal surface helps in understanding conditions favoring CUI.
The use of transient hygrothermal models for moisture control is well established in the building insulation design codes and standards. The building designs naturally shed the liquid water to minimize entry and facilitate vapor management so that moisture doesn’t accumulate within building. Several building industry hygrothermal models have been developed and are available for commercial use. One such commercial model has been used to understand water transport in a CUI application. The case study involves evaluation of piping and equipment installed with a closed cell polyurethane insulation. The hygrothermal model provided insights on the parameters influencing the time of wetness and the ease of water escaping the equipment-insulation-jacketing system.
Thermal insulation is used in the exterior of equipment and piping for different applications such as heat conservation, freeze protection, cold conservation. The insulated equipment usually experiences corrosion under the insulation due to the trapped water beneath the insulation. Many factors such as duration and frequency of moisture exposure, corrosivity of the water, insulation type, exposure temperature, climactic conditions, weather proofing condition affect the amount of CUI damage.
A simple set-up and methodology was developed to semi-quantitatively measure water transport (liquid and vapor) through intact and damaged insulation when a thermal gradient across the insulation is maintained. The main objective was to contribute to a better understanding of water transport mechanism in different insulation materials which can be related to corrosion under insulation (CUI). Most tests were conducted using closed cell polyurethane (PU) insulation. For comparison purposes, tests were conducted with mineral wool insulation as well as with insulation externally covered with water vapor permeable or impermeable layers. Due to size limitations, only PU results will be presented.
Results from this study indicated different time scales for the following main processes affecting the moisture content at the metal/insulation interfaced) Water transport from the environment to the metal surface through intact insulation. 2) Water transport from the environment to the metal surface through damaged insulation. 3) Water transport out of the metal surface through the insulation. A potentially effective approach for CUI mitigation based on this understanding is illustrated.
Corrosion under Insulation (CUI) is an important integrity threat and a significant contributor to leaks in many industries (Oil and Gas: Production, Transport (pipelines) and Refining; Chemical and Petrochemical Plants; etc.)1-3. This type of corrosion can cause failures in areas that are not normally of a primary concern to an inspection program. The failures can be catastrophic because the corrosion typically occurs over a sizeable surface area. The rate of CUI depends on several factors, such as the amount and composition (e.g. chloride content) of water present beneath the insulation, availability of oxygen, and temperature.
It has been recognized that a critical factor controlling CUI is the presence of moisture (liquid water) at the steel surface. However, the minimum amount of moisture required to sustain CUI has not been quantified for different insulating materials. For warm / hot piping, there is a thermodynamic driving force to move the water away from the pipe surface and hence reduce likelihood of corrosion unless the overall system is unable to remove the moisture causing corrosion.
Integration of well and reservoir surveillance techniques: production measurements, reservoir fluid characterization, pressure transient analysis, production logging, relative permeability, and fractional flow are critical in understanding well and reservoir performance for an adequate well and field management specially in a high cost interventions environment.
Well productivity deterioration for a specific well was identified based on production testing and well performance nodal analysis (NA). The productivity deterioration was then confirmed by means of pressure transient analysis (PTA). Standard diagnostic derivative analyses suggested that permeability decrease was the main source of performance detriment due to an apparent transmissibility reduction of 60%. Since water breakthrough took place before productivity impairment was acknowledged, the immediate reaction was to establish the hypothesis that effective permeability reduction due to relative permeability effects was the main reason for the impairment. A multilayer (ML) PTA type curve model together with fractional flow analysis did not support the relative permeability premise as the primary cause, leaving the potential for severe plugging of the reservoir rock as the predominant hypothesis.
A production logging tool (PLT) was run confirming that about 60% of the completed interval was not producing at the expected levels. It was possible to separate the relative permeability effects from the plugging effects using the integrated technique described above. Relative permeability effects contributed to production impairment with an equivalent effective thickness of 14% and plugging effects impacted an equivalent effective thickness of 46%. A coiled tubing (CT) mud acid treatment was performed recovering approximately 65% of the transmissibility lost and decreasing formation skin from 16 to 9. This intervention delivered an instantaneous oil production benefit of approximately 7,000 STBOD. This analysis approach has been recommended to determine potential benefit of future intervention candidates.
This paper presents an innovative approach to consider fractional flow as part of pressure transient analysis interpretation. This level of integration is not a common practice because PTA theory was developed for single phase and most of the commercial software products do not consider multiphase interpretations in analytical PTA. These limitations leave out the actual effect of relative permeability in the estimated transmissibility values.