Intiso, Luciana (Rina Consulting - Centro Sviluppo Materiali) | Smith, Viviane C. M. (BP Exploration Operating Co. Limited) | Tahirov, Tahir (BP Exploration Operating Co. Limited) | Mohiuldin, Ghulam (BP Exploration Operating Co. Limited) | Scoppio, Lucrezia (Pipe Team srl) | Smith, Lee (BP Exploration Operating Co. Limited) | El-Kassar, Mohamed (BP Exploration Operating Co. Limited)
High pressure high temperature (HPHT) Oil and Gas developments often require high density clear brines for well completion fluids used in the final stages of well construction. Formate and bromide brines are two which are commonly used. Heavy completion brines can, however, pose a corrosion and cracking threat, especially if the pH reduces or the brine degrades under high pressure/high temperature conditions. This latter threat can be problematic where the completion design permits brine to be trapped in the completion for an extended period, especially if further contaminated with formation treatment chemicals and formation fluids. Laboratory testing was conducted to explore the credibility of such a threat for two candidate completion brines. In the present work, a buffered mixed formate and a proprietary bromide brine were tested under 14Bar CO2 at 140°C. The materials tested were: super martensitic stainless steel (UNS(1) S41426) tubular, super duplex stainless steel UNS S39274 tubular, API 5CT/ ISO 11960 grade ”C125” casing and nickel alloy (UNS N08825). The paper presents the specific corrosion and cracking threats introduced by the brines.
High density brines are commonly used for high-pressure well completion fluids used in final stages of well construction. Heavy brines can, however, pose a corrosion and/or cracking threat if the pH reduces or the brine degrades, resulting in the formation of aggressive species.1,2,3 Heavy brines are typically solutions of bromides and/or formates. The heaviest formate brines include caesium compounds, whilst the lightest contain only sodium and/or potassium compounds.
Bromide brines have generally been considered benign towards metals, provided that the package of additives is appropriate for the well (buffering, corrosion inhibition and oxygen scavenging).8,9 Whilst some issues have been encountered, where the additives have been in line with good practice these have mostly been due to atypical service scenarios or brines based on the most aggressive of divalent cations (Zn2+).
Scoppio, Lucrezia (Pipe Team srl) | Imbimbo, Emilia (RINA CONSULTING-Centro Sviluppo Materiali) | Axelsen, Sten (Statoil ASA) | Nice, Perry (Statoil ASA) | Mortali, Giuseppe (RINA CONSULTING-Centro Sviluppo Materiali)
Acid systems are used to improve productivity through either near-wellbore damage removal or through dissolving scale inside the wellbore during production. This paper describes the qualification methodology applied in the search for effective scale dissolvers/stimulation fluids with low corrosivity. The identification of suitable acid systems is becoming increasingly more challenging.
Furthermore, the operators try to lower the cost of the acid treatment itself. This may be achieved through optimization of the inhibitor package, which constitutes a significant part of the chemical cost.
A corrosion testing program was performed aimed at evaluating scale dissolver packages to determine which package(s) were least corrosive and acceptable for use in wells constructed with 3Cr80 alloyed steel and L80 13 Cr (API 5CT grade) (1) tubulars. Laboratory exposure corrosion tests were carried out at 60°C and 80°C. The scale dissolver packages consisted of 7.5%HCl, 15%HCl and 28%HCl including corrosion inhibitor packages. The main challenge was to optimize the acid formulation for 3Cr 80 alloyed steel. There is only limited data available for this material.
Corrosion resistance of the tested alloys was evaluated in terms of mass loss and localized corrosion. The results of this program successfully identified the optimized scale dissolver packages for both 3Cr80 alloyed steel and L80 13 Cr (API 5CT grade), respectively.
Acid systems are commonly used to improve productivity through either near-wellbore damage removal or through dissolving scale inside the wellbore during production. A number of different acid stimulation packages are available for removal of debris to permit unrestricted hydrocarbon flow. Acidic fluids can include different types of acids, such as hydrochloric (HCl), acetic, formic, or combinations of such acids. Since these can be corrosive, corrosion inhibitor packages are required to prevent severe corrosion damage to the well construction materials. Furthermore, inhibition additives for acid systems usage in North Sea oil wells require adherence to regulations calling for continual improvement in environmental characteristics while maintaining performance.1 As environmental standards are continually tightened, especially in the North Sea area, options for different corrosion inhibitor chemistries that will meet the criteria are becoming more limited. Challenging conditions for acid inhibition are ever present with (1) high temperatures, and (2) the use of metallurgies, e.g. 3Cr80 alloy steel, for which only limited data on scale treatments is available.2,3 3Cr80 has been developed as an economical material alternative for moderately corrosive services, and has been in service for more than 16 years as tubing on the Norwegian Continental Shelf (NCS).3
Nice, Perry (Statoil ASA) | Amaya, Hisashi (Nippon Steel & Sumitomo Metal Corporation) | Scoppio, Lucrezia (Pipe Team srl) | Larche, Nicolas (French Corrosion Institute) | Matsuda, Yuya (Nippon Steel & Sumitomo Metal Corporation) | Fiocchi, Matteo (S&L Consulting)
ABSTRACTIn seawater handling systems, the available well tubing materials are Glass Reinforced Epoxy lined low alloy steel or Corrosion Resistant Alloy's (CRA) such as super duplex stainless steel. However, in treated seawater the corrosion risk can be controlled so that lower grade alloys can be considered. Recent efforts have focused attention on better dissolved oxygen controls which permits the investigation and possible use of more cost effective materials such as the duplex stainless steel UNS S82551. Full scale corrosion testing of tubes joined together with a proprietary premium threaded connection was performed in controlled seawater loops simulating service conditions at 30°C. The flow rate and dissolved oxygen were controlled at 5 m/s and <20ppb, respectively. Weekly dissolved oxygen excursions corresponding to 24h at 100ppb followed by 1 hour at 300ppb were included during the 5 months exposure. Corrosion results of UNS S82551 tubing were compared to UNS S31803 and UNS S39274. In parallel, laboratory exposures of coupons were performed in dissolved oxygen controlled cells with and without CREVCORR crevice formers, allowing the measurement of electrochemical potentials as function of dissolved oxygen content (e. g. biofilm ennoblement monitoring) and the related corrosion resistance. The results showed that dissolved oxygen content should be properly controlled below critical values to avoid crevice corrosion of the lesser alloyed duplex stainless steels. In the full scale loop test, UNS S82551 tubes did not exhibit crevice corrosion at threaded connection interfaces under the defined test conditions.INTRODUCTIONIn treated seawater injection wells, the corrosion risk can be controlled permitting low alloy steel to be considered for equipment and tubing, provided the dissolved oxygen concentrations (DOC) are held below 20ppb. Nevertheless, experience has shown that treated seawater injection systems, if not correctly operated, can experience high DOC in the seawater injected into the wells resulting in corrosion failures. The time to failure can be exacerbated further by high shear stresses or erosion-corrosion caused by high injection rates creating unacceptably high velocities within the tubing. Publications by Nice et al identified that alloying grade L80 steel with small quantities of chromium (0.5 to 1.0%) could provide improved tubing longevity in treated seawater injection systems.1, 2 Work by Silverman et al supports these findings for grade Q-125 tubing.3 But again this testing showed unacceptably high injection rates will have a negative impact on this improvement. By limiting the seawater flow velocity to below 5m/s both laboratory testing and experience have shown to give enhanced tubing lifetimes. Silverman findings would support this limit w.r.t tubing longevity with the reported flow velocities in the order of maximum 4m/s.3
Intiso, Luciana (Centro Sviluppo Materiali S.p.A) | Mortali, Giuseppe (Centro Sviluppo Materiali S.p.A) | Guedes, Flávia (PETROBRAS R&D Center) | Berry, Sandra (Baker Hughes) | Nice, Perry (Statoil ASA) | Scoppio, Lucrezia (Pipe Team srl) | Baptista, Ilson Palmieri (PETROBRAS R&D Center) | Carreno Velasco, Javier Alejandro (Instituto Nacional de Tecnologia)
ABSTRACTDuring the completion operations of High pressure (HP) wells the perforated pay zone may require acid stimulation to remove and clean up debris and therefore permit unrestricted hydrocarbon flow. Also later in the well life, carbonate scale may deposit that can restrict the wellbore thus limiting production this is normally removed with the aid of a scale dissolver treatment(s). These chemicals can be very corrosive towards well construction materials. Hence the need to assess acid stimulation and scale dissolver chemical packages to prevent severe corrosion damage to the wells tubular sand equipment. For this reason, laboratory testing of these chemical packages plays an important role. However, it has been observed that the experimental parameters can heavily influence the results. In particular, it has been shown that critical parameters like the pressure, solution volume/test specimen area ratio, temperature ramp up and cooling times as well as post-test specimen treatment are key to achieving reliable test results. Also it is important not only to choose the correct test parameters but also to scrutinize the test set-up such that it replicates the treatment application as closely as possible. Once established the test procedure needs to be detailed to allow inter-laboratory testing replication. With this purpose in mind a testing program was designed using high strength martensitic and duplex stainless steels, namely, UNS S41426, 17CR (17Cr-4Ni-2.5Mo-1Cu) and UNS S39274. A round robin testing program was carried out between two laboratories using a 15% HCl based scale dissolver package at 110°C. The results underlined the importance of proper alignment of test parameters between laboratories and eventually led to acceptable agreement between the laboratories results.INTRODUCTIONIn high pressure (HP) wells are present challenging conditions for drilling and well completion operations. During the completion operations of these wells the perforated pay zone may require acid stimulation to remove and clean up debris and therefore permit unrestricted hydrocarbon flow. Also later in the well life, carbonate scale may deposit which will need to be removed to unblock the wellbore with a scale dissolver treatment.
Nice, Perry (Statoil ASA) | Intiso, Luciana (Centro Sviluppo Materiali S.p.A.) | Nasvik, Håvard (Statoil ASA) | Schultz, Katrina (TETRA Technologies, Inc.) | Takabe, Hideki (Nippon Steel & Sumitomo Metal Corporation) | Scoppio, Lucrezia (Pipe Team srl) | Vasquez, Auristela (Statoil ASA) | Lee, Dave (TETRA Technologies, Inc.) | Amaya, Hisashi (Nippon Steel & Sumitomo Metal Corporation) | Mortali, Giuseppe (Centro Sviluppo Materiali S.p.A.)
The recent development of high strength corrosion resistant alloy UNS S42028 has opened up opportunities for the use of cost effective material solutions for applications such as high collapse liner sections in high pressure high temperature (HPHT) reservoirs.
An important aspect with such a development in this application is an understanding of the environmental cracking behavior of Alloy UNS S42028 when exposed to clear brine fluids. This is particularly important during the completion phase of HPHT wells when medium density clear brine fluids are required.
This paper will detail the environmental cracking test program and results when Alloy UNS S42028 was exposed to medium density bromide based clear brine fluids at a temperature of 150°C (302°F).
The oil industry is pushing the drilling-technology frontier forward with enthusiasm, despite the high costs of drilling deep wells.1 Numerous operating companies are pursuing new and much deeper geologic horizons, drilling wells and searching for new sources of oil and gas in environments not previously explored. 2 However, as well depths increase, wellbore construction and production operations become much more challenging because of the extreme high-pressure/high-temperature (HPHT) environments. The downhole conditions in a long term production setting of 30 years, or even more, expose these wells to loads and corrosive conditions that test the limits of downhole tools and equipment. 3
Operators now require completions for wells up to 20000 psi wellhead pressures and temperatures up to 150°C as a result of exploring further offshore, drilling in deeper water, and drilling to greater well depths. 4 Hence, completion engineers are engaged in finding new materials to provide safe and durable well completions. 1 As an example of this effort, the recent development of the high strength corrosion resistant alloy UNS (1) S42028 has opened up opportunities for the use of cost effective material solutions for applications such as high collapse liner , in HPHT reservoirs. 5, 6
Scoppio, Lucrezia (Pipe Team srl) | Nice, Perry (Statoil ASA) | Mortali, Giuseppe (Centro Sviluppo Materiali SpA) | Intiso, Luciana (Centro Sviluppo Materiali SpA) | Piccolo, Eugenio Io (Centro Sviluppo Materiali SpA) | Nasvik, Havard (Statoil ASA) | Cassidy, Juanita (Halliburton) | Amaya, Hisashi (Nippon Steel & Sumitomo Metal Corp.)
Completion designs for deep water high pressure wells commonly require corrosion resistant alloy (CRA) tubing grades with minimum specified yield strengths of 125 ksi to resist against high tensile and collapse loads as well as corrosive reservoir fluids. The types of alloys considered for such well designs and corrosive environments are 17%Cr and super duplex stainless steels (UNS(1) S39274).
On completion of these wells the perforated pay zone may require acid stimulation to remove debris and therefore permit unrestricted hydrocarbon flow. Also later in the well life, carbonate scale may deposit in the completion which needs to be removed with a scale dissolver treatment.
A corrosion testing program aimed at evaluating stimulation acid/scale dissolver packages was designed and performed to determine which package(s) were least corrosive and acceptable for use with wells constructed with 17%Cr and super duplex stainless steels tubulars. Corrosion tests were carried out at temperatures between 70 to 130°C. The stimulation acid/scale dissolver packages consisted of 10%HCl, 15%HCl, and %HCl plus 1%HF including corrosion inhibitors and inhibitor intensifiers. The range of applicability and compatibility against the tested alloys was defined.
Piccolo, E.Lo (Centro Sviluppo Materiali SpA) | Nice, P.I. (Statoil ASA) | Fattnes, O. (Statoil ASA) | Morana, R. (Centro Sviluppo Materiali SpA) | Bufalini, A. (Centro Sviluppo Materiali SpA) | Lucci, A. (Centro Sviluppo Materiali SpA) | Scoppio, L. (Pipe Team srl)