Barite-Free Non-Aqueous Drill-In Fluid System Maximizes Productivity in High Temperature Wells

2021 ◽  
Author(s):  
Godwin Chimara ◽  
Wael Amer ◽  
Stephane L'Hostis ◽  
Philip Leslie
Keyword(s):  
High Temperature ◽  
Acid Treatment ◽  
Fluid System ◽  
Free System ◽  
Well Completion ◽  
Internal Phase ◽  
Open Hole ◽  
Enhance Efficiency ◽  
Well Data ◽  
Response Testing

Abstract Minimizing formation damage is vital for maximizing productivity when an openhole (slotted liner) completion strategy is used, and it is particularly challenging in high temperature wells with bottomhole static temperature approaching 190°C (374°F). A barite-weighted fluid system for such high temperature wells was identified as unsuitable due to lack of ability to remediate via acid treatment. This paper discusses how a customized barite-free non-aqueous drill-in fluid system was used to successfully achieve productivity objectives for three such wells. Based on reservoir and well data provided, a 1.15 to 1.20 sg (9.60 to 10.0 lbm/gal) barite-free, non-aqueous drill-in fluid system was designed using a high density calcium chloride/calcium bromide brine as the internal phase to compensate for the absence of barite as a weighting agent. An engineered acid-soluble bridging package was included to protect the reservoir from excess filtrate invasion and allow for potential remediation by acid treatment at a later stage. The fluid system was subjected to formation response testing, and the results obtained proved satisfactory, confirming the fluid system was suited for drilling the reservoir. A similar solids-free system using higher density brine as the internal phase, was also formulated. This was spotted in the open hole once drilling was completed to help eliminate any potential for solids settling before running the slotted liner. Three wells were successfully drilled and completed. The barite-free system remained stable, allowed for trouble-free fluids-handling and drilling operations, and performed as expected. To aid in minimizing fluid invasion into the reservoir, onsite particle size distribution (PSD) measurements were performed in order to optimize bridging material additions while drilling and enhance efficiency in managing the solids control system. Because of the extremely high bottomhole temperature, a mud cooler was installed to help control the flowline temperature below 60°C (140°F); this helped maintain fluid stability and preserve functionality of downhole tools in this hostile environment. The solids-free system was successfully spotted in the open hole after drilling the section before well completion. This eliminated any settling potential and reduced flowback of solids during production. The recorded productivity of these wells met expectations.

Case History of Matrix Acid Stimulation using Specialized Acid Composition for High Temperature Carbonate Formation and Long Interval Section

2021 ◽  
Author(s):  
M. D. Elsa
Keyword(s):  
High Temperature ◽  
Lessons Learned ◽  
Interval Length ◽  
Matrix Acidizing ◽  
High Co2 ◽  
Water Loading ◽  
Well Completion ◽  
Carbonate Formation ◽  
Open Hole ◽  
Well Tests

Alur Siwah field is located onshore in Block A PSC of PT Medco E&P Malaka, Aceh Province. Six of the ten drilled wells proved significant gas column in Peutu limestone and Tampur dolostone. Well tests indicated gas rates in the range of 0.2 – 42 MMSCFD from selected intervals in both formations. Estimated permeability values from well tests are in range of 0.6 – 3.7 mD. During drilling campaign in 2018 three wells was drilled with total depth around 9,500 ft TVD. AS-9A, AS-11 and AS-12 wells penetrated Peutu Limestone and TD was 213 ft TVD above common GWC. These three wells were completed with open hole and pre-drilled liner, the interval length ranging from 300 to 500 ft-MD. Since Peutu limestone has low permeability the reservoir needs stimulation to increase productivity, maintain gas sales according to GSA (Gas Sales Agreement), and optimize reservoir depletion. Matrix acidizing treatment was applied to remove formation damage. The method was proven successful in previous well at Alur Siwah field in 1990’s. Peutu limestone challenges are high temperature (360 degF), high CO2 (up to 25%), high H2S content (up to 12,000 ppm), long interval open hole section (300-500 ft-MD), and water encroachment risk from water bearing zone. High temperature will accelerate acid reaction, and premature reaction might occur before reaching the reservoir. High CO2 & H2S might cause corrosion at completion string. Penetration into water bearing could cause water encroachment and water loading issue. With proper fluid selection, acid placement method, volume treatment design and execution, matrix acidizing can be applied safely and successfully to stimulate high temperature gas wells which have long interval open hole section completed with pre-drilled liner without water loading issue. This paper covers the application of acid stimulation in Alur Siwah field, well completion, post treatment well performance, best practices and lessons learned.

Effects of hygrothermal and thermal-oxidative ageing on the open-hole properties of T800/high-temperature epoxy resin composites with different hole shapes

2019 ◽  
Vol 32 (3) ◽  
pp. 306-315 ◽  
Author(s):  
Liang Xu ◽  
Yi He ◽  
Shaohua Ma ◽  
Li Hui
Keyword(s):  
Compressive Strength ◽  
High Temperature ◽  
Epoxy Resin ◽  
Failure Modes ◽  
Resin Composites ◽  
Physical Ageing ◽  
Hygrothermal Ageing ◽  
Open Hole ◽  
Epoxy Resin Composites ◽  
Oxidative Ageing

T800/high-temperature epoxy resin composites with different hole shapes were subjected to hygrothermal ageing and thermal-oxidative ageing, and the effects of these different ageing methods on the open-hole properties of the composites were investigated, including analyses of the mass changes, surface topography changes (before and after ageing), fracture morphologies, open-hole compressive performance, dynamic mechanical properties and infrared spectrum. The results showed that only physical ageing occurred under hygrothermal ageing (70°C and 85% relative humidity), and the equilibrium moisture absorption rate was only approximately 0.72%. In contrast, under thermal-oxidative ageing at 190°C, both physical ageing and chemical ageing occurred. After ageing, the open-hole compressive strength of the composite laminates with different hole shapes decreased significantly, but the open-hole compressive strength after thermal-oxidative ageing was greater than that after hygrothermal ageing. Among the aged and unaged laminates, the laminates with round holes exhibited the largest open-hole compressive strength, followed by those with the elliptical holes, square holes and diamond holes. The failure modes of the laminates were all through-hole failures. The unaged samples had a glass transition temperature ( T g) of 226°C, whereas the T g of the samples after hygrothermal ageing was 208°C, which is 18°C less than that of the unaged samples, and the T g of the samples after thermal-oxidative ageing was 253°C, which is 27°C greater than that of the unaged samples.

The Feasibility for Potassium-Based Phosphate Brines To Serve as High-Density Solid-Free Well-Completion Fluids in High-Temperature/High-Pressure Formations

SPE Journal ◽  
2018 ◽  
Vol 24 (05) ◽  
pp. 2033-2046 ◽  
Author(s):  
Hu Jia ◽  
Yao–Xi Hu ◽  
Shan–Jie Zhao ◽  
Jin–Zhou Zhao
Keyword(s):  
High Pressure ◽  
High Temperature ◽  
Oil And Gas ◽  
Pressure Coefficient ◽  
High Density ◽  
Well Drilling ◽  
Well Completion ◽  
Oil And Gas Resources ◽  
Completion Fluids ◽  
High Temperature High Pressure

Summary Many oil and gas resources in deep–sea environments worldwide are often located in high–temperature/high–pressure (HT/HP) and low–permeability reservoirs. The reservoir–pressure coefficient usually exceeds 1.6, with formation temperature greater than 180°C. Challenges are faced for well drilling and completion in these HT/HP reservoirs. A solid–free well–completion fluid with safety density greater than 1.8 g/cm3 and excellent thermal endurance is strongly needed in the industry. Because of high cost and/or corrosion and toxicity problems, the application of available solid–free well–completion fluids such as cesium formate brines, bromine brines, and zinc brines is limited in some cases. In this paper, novel potassium–based phosphate well–completion fluids were developed. Results show that the fluid can reach the maximum density of 1.815 g/cm3 at room temperature, which makes a breakthrough on the density limit of normal potassium–based phosphate brine. The corrosion rate of N80 steel after the interaction with the target phosphate brine at a high temperature of 180°C is approximately 0.1853 mm/a, and the regained–permeability recovery of the treated sand core can reach up to 86.51%. Scanning–electron–microscope (SEM) pictures also support the corrosion–evaluation results. The phosphate brine shows favorable compatibility with the formation water. The biological toxicity–determination result reveals that it is only slightly toxic and is environmentally acceptable. In addition, phosphate brine is highly effective in inhibiting the performance of clay minerals. The cost of phosphate brine is approximately 44 to 66% less than that of conventional cesium formate, bromine brine, and zinc brine. This study suggests that the phosphate brine can serve as an alternative high–density solid–free well–completion fluid during well drilling and completion in HT/HP reservoirs.

Microstructural Evolution and Thermal Stability Characterization of a High Temperature Die Attach Lead-Free System

2012 ◽  
Vol 2012 (HITEC) ◽  
pp. 1-11 ◽  
Author(s):  
Rogie I. Rodriguez ◽  
Dimeji Ibitayo ◽  
Pedro Quintero
Keyword(s):  
High Temperature ◽  
Melting Point ◽  
Microstructural Evolution ◽  
Diffusion Mechanism ◽  
Processing Temperature ◽  
Mechanical And Thermal Properties ◽  
Promising Alternative ◽  
Free System ◽  
Die Attach

There is a need for electromechanical devices capable of operating in high temperature environments (>200°C) for a wide variety of applications. Today's wide-bandgap (WBG) semiconductor based power electronics have demonstrated a potential of operating above 400°C, however they are still limited by packaging. Among the most promising alternative is the Au-Sn eutectic solder, which have been widely used due to its excellent mechanical and thermal properties. However, the operating temperature of this metallurgical system is still limited to ∼250°C owing to its melting temperature of 280°C. Therefore, a higher temperature resistant system is much needed, but without affecting the current processing temperature of ∼325°C typically exhibited in most high temperature Pb-Free solders. This paper presents the development and characterization of a fluxless die attach soldering process based on gold enriched solid liquid inter-diffusion (SLID). A low melting point material (eutectic Au-Sn) was deposited in the face of a substrate, whereas a high melting point material, gold in this instance, was deposited in its mating substrate. Deposition of all materials was performed using a jet vapor deposition (JVD) equipment where thicknesses were controlled to achieve specific compositions in the mixture. Sandwiched coupons where isothermally processed in a vacuum reflow furnace. SEM and EDS were employed to reveal the microstructural evolution of the samples in order to study the interfacial reactions of this fluxless bonding process. Mechanical characterization of the each individual intermetallic phase was achieved by nanoindentation. Differential scanning calorimetry demonstrated the progression of the SLID process by quantifying the remaining low melting point constituent as a function of time and temperature. Post-processed samples confirmed the inter-diffusion mechanism as evidenced by the formation of sound joints that proved to be thermally stable up to ∼490°C after the completion of the SLID process.

A Case Study : Innovative Open Hole Well Completion Provides Superior Results in Tigh Gas Formation in Jilin District, China

2013 ◽  
Author(s):  
Wang Feng ◽  
Changyu Liu ◽  
Yingan Zhang ◽  
Yong Wang ◽  
Hai Liu ◽  
...  
Keyword(s):  
Well Completion ◽  
Gas Formation ◽  
Open Hole

Reduced-Polymer-Loading, High-Temperature Fracturing Fluids by Use of Nanocrosslinkers

SPE Journal ◽  
2016 ◽  
Vol 22 (02) ◽  
pp. 622-631 ◽  
Author(s):  
Feng Liang ◽  
Ghaithan Al-Muntasheri ◽  
Hooisweng Ow ◽  
Jason Cox
Keyword(s):  
High Temperature ◽  
Gas Flow ◽  
Laboratory Data ◽  
Gelling Agent ◽  
Formation Damage ◽  
Fluid System ◽  
Temperature Range ◽  
Enhanced Production ◽  
Fracturing Fluids ◽  
Polymer Loading

Summary In the quest to discover more natural-gas resources, considerable attention has been devoted to finding and extracting gas locked within tight formations with permeability in the nano- to microdarcy range. The main challenges associated with working in such formations are the intrinsically high-temperature and high-pressure bottom conditions. For formations with bottomhole temperatures at approximately 350–400°F, traditional hydraulic-fracturing fluids that use crosslinked polysaccharide gels, such as guar and its derivatives, are not suitable because of significant polymer breakdown in this temperature range. Fracturing fluids that can work at these temperatures require thermally stable synthetic polymers such as acrylamide-based polymers. However, such polymers have to be used at very-high concentrations to suspend proppants. The high-polymer concentrations make it very difficult to completely degrade at the end of a fracturing operation. As a consequence, formation damage by polymer residue can reduce formation conductivity to gas flow. This paper addresses the shortcomings of the current state-of-the-art high-temperature fracturing fluids and focuses on developing a less-damaging, high-temperature-stable fluid that can be used at temperatures up to 400°F. A laboratory study was conducted with this novel system, which comprises a synthetic acrylamide-based copolymer gelling agent and is capable of being crosslinked with an amine-containing polymer-coated nanosized particulate crosslinker (nanocrosslinker). The laboratory data have demonstrated that the temperature stability of the crosslinked fluid is much better than that of a similar fluid lacking the nanocrosslinker. The nanocrosslinker allows the novel fluid system to operate at significantly lower polymer concentrations (25–45 lbm/1,000 gal) compared with current commercial fluid systems (50–87 lbm/1,000 gal) designed for temperatures from 350 to 400°F. This paper presents results from rheological studies that demonstrate superior crosslinking performance and thermal stability in this temperature range. This fracturing-fluid system has sufficient proppant-carrying viscosity, and allows for efficient cleanup by use of an oxidizer-type breaker. Low polymer loading and little or no polymer residue are anticipated to facilitate efficient cleanup, reduced formation damage, better fluid conductivity, and enhanced production rates. Laboratory results from proppant-pack regained-conductivity tests are also presented.

A Novel Viscoelastic Surfactant Fluid System Incorporating Nanochemistry for High-Temperature Gravel Packing Applications

2018 ◽  
Author(s):  
Nirupama Vaidya ◽  
Valerie Lafitte ◽  
Sergey Makarychev-Mikhailov ◽  
Mohan Kanaka Raju Panga ◽  
Chidi Nwafor ◽  
...  
Keyword(s):  
High Temperature ◽  
Fluid System ◽  
Gravel Packing ◽  
Viscoelastic Surfactant

Study on Influx Risk Evaluation of Horizontal Gas Wells With High-Pressure High-Temperature in the South China Sea

2020 ◽  
Author(s):  
Ming Luo ◽  
Deli Gao ◽  
Xin Zhao ◽  
Yuan Chen ◽  
Yupeng Yang ◽  
...  
Keyword(s):  
High Pressure ◽  
High Temperature ◽  
South China Sea ◽  
Risk Evaluation ◽  
Control Strategies ◽  
Control Design ◽  
Gas Wells ◽  
Well Control ◽  
High Pressure High Temperature ◽  
Open Hole

Abstract The South China Sea has rich natural gas source with typical high-pressure high-temperature (HPHT) and the extremely narrow drilling window, which leads to frequent influx, even borehole abandonment. However, horizontal gas wells have been placed in the area to develop the gas reservoir, which presents greater well control challenges. Therefore, the influx risk evaluation is quite necessary to guide the well control design. Firstly, the influx mechanism is analyzed based on gas intrusion to provide a theoretical basis for well control design. It is found that influx usually occurs when drilling the high-temperature stratums and target layers. Secondly, the relationship between horizontal open-hole length and influx volume is calculated under different reservoir permeability, reservoir thickness, negative bottom hole pressure and horizontal open-hole section length. Thirdly, the characteristics of gas-liquid two-phase flow are described. Fourthly, the inflow risk evaluation and well control strategies of the target horizontal gas wells are proposed, and the influx risk evaluation envelope was established. The influx risk evaluation and well control strategies have been successfully applied to the DF gas field featuring offshore HPHT. Horizontal gas wells were drilled in the micro pressure window without accidents and the well cost was significantly reduced.

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