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.

Integration of Post-Fracturing Spectral Noise Log, Temperature Modeling, and Production Log Diagnoses Water Production and Resolves Uncertainties in Openhole Multistage Fracturing

2021 ◽  
Author(s):  
Adnan Bin Asif ◽  
Jon Hansen ◽  
AbdulMuqtadir Khan ◽  
Mohamed Sheshtawy
Keyword(s):  
High Temperature ◽  
Fracture Initiation ◽  
Interval Length ◽  
Valuable Insight ◽  
Flow Profile ◽  
Tight Gas ◽  
Well Completion ◽  
Temperature Modeling ◽  
Integrated Diagnosis ◽  
Array Production

Abstract Hydrocarbon development from tight gas sandstone reservoirs is revolutionizing the current oil and gas market. The most effective development strategy for ultralow- to low-permeability reservoirs involves multistage fracturing. A cemented casing or liner completed with the plug-and-perf method allows nearly full control of fracture initiation depth. In uncemented completions equipped with fracturing sleeves and packers, clearly identifying the fracture initiation points is difficult due to lack of visibility behind the completion and long openhole intervals between packers. Also, the number of fractures initiated in each treatment is uncertain. A lateral was completed with access to 3,190 ft of openhole section across five fracturing stages in a high-temperature and high-pressure tight-gas interval. All stages were successfully stimulated, fracture cleanup flowback was conducted, and entry ports were milled out. A high-definition spectral noise log (SNL) was then conducted along with numerical temperature modeling. Additional logging was done with a set of conventional multiphase sensors. A multi-array production log suite was also performed. Finally, the bottom four stages were isolated with a high-temperature isolation plug based on the integrated diagnosis. The SNL helped to analyze the isolation packer integrity behind the liner. The initiation of multiple fractures was observed, with as many as nine fractures seen in a single-stage interval. A correlation was found between the openhole interval length and the number of fractures. A correlation of fracture gradient (FG) and initiation depths was made for the lateral in a strike-slip fault regime. The fractures were initiated at depths with low calculated FG, confirming the conventional understanding and increasing confidence in rock property calculations from openhole log data. SNL and temperature modeling aided quantitative assessment of flowing fractures and stagewise production behind the liner. Multi-array production logging results quantified the flow and flow profile inside the horizontal liner. The production flow assessments from both techniques were in good agreement. The integration of several datasets was conducted in a single run, which provided a comprehensive understanding of well completion and production. High water producing intervals were isolated. Downstream separator setup after the isolation showed a water cut reduction by 95%. The integration of the post-fracturing logs with the openhole logs and fracturing data is unique. The high-resolution SNL provided valuable insight on fracture initiation points and the integrity of completion packers. Fracturing efficiency, compared to the proppant placed, provides treatment optimization for similar completions in the future.

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.

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.

Case History: Coring in ERD Well with Collision Risk Challenge and Optimization of Coring Parameters Based on Previous Coring Jobs in Carbonate Formation Alleviated Core Recovery

2021 ◽  
Author(s):  
Rahul Kamble ◽  
Youssef Ali Kassem ◽  
Kshudiram Indulkar ◽  
Kieran Price ◽  
Majid Mohammed A. ◽  
...  
Keyword(s):  
United Arab Emirates ◽  
Lessons Learned ◽  
Low Flow ◽  
High Angle ◽  
Collision Risk ◽  
Pilot Hole ◽  
Field Development ◽  
Core Recovery ◽  
Carbonate Formation ◽  
Carbonate Formations

Abstract Coring during the development phase of an oil and gas field is very costly; however, the subsurface insights are indispensable for a Field Development Team to study reservoir characterization and well placement strategy in Carbonate formations (Dolomite and limestone with Anhydrite layers). The objective of this case study is to capture the successful coring operation in high angle ERD wells, drilled from the fixed well location on a well pad of an artificial island located offshore in the United Arab Emirates. The well was planned and drilled at the midpoint of the development drilling campaign, which presented a major challenge of wellbore collision risk whilst coring in an already congested area. The final agreed pilot hole profile was designed to pass through two adjacent oil producer wells separated by a geological barrier, however, the actual separation ratio was < 1.6 (acceptable SF to drill the well safely), which could have compromised the planned core interval against the Field Development Team's requirement. To mitigate the collision risks with offset wells during the coring operation, a low flow rate MWD tool was incorporated in the coring BHA to monitor the well path while cutting the core. After taking surveys, IFR and MSA corrections were applied to MWD surveys, which demonstrated an acceptable increase in well separation factor as per company Anti-Collision Risk Policy to continue coring operations without shutting down adjacent wells. A total of 3 runs incorporating the MWD tool in the coring BHA were performed out of a total of 16 runs. The maximum inclination through the coring interval was 73° with medium well departure criteria. The main objective of the pilot hole was data gathering, which included a full suite of open hole logging, seismic and core cut across the target reservoir. A total of 1295 ft of core was recovered in a high angle well across the carbonate formation's different layers, with an average of 99% recovery in each run. These carbonate formations contain between 2-4% H2S and exhibit some fractured layers of rock. To limit and validate the high cost of coring operations in addition to core quality in the development phase, it was necessary to avoid early core jamming in the dolomite, limestone and anhydrite layers, based on previous coring runs in the field. Core jamming leads to early termination of the coring run and results in the loss of a valuable source of information from the cut core column in the barrel. Furthermore, it would have a major impact on coring KPIs, consequently compromising coring and well objectives. Premature core jamming and less-than-planned core recovery from previous cored wells challenged and a motivated the team to review complete field data and lessons learned from cored offset wells. Several coring systems were evaluated and finally, one coring system was accepted based on core quality as being the primary KPI. These lessons learned were used for optimizing certain coring tools technical improvements and procedures, such as core barrel, core head, core handling and surface core processing in addition to the design of drilling fluids and well path. The selection of a 4" core barrel and the improved core head design with optimized blade profile and hold on sharp polished cutters with optimized hydraulic efficiency, in addition to the close monitoring of coring parameters, played a significant role in improving core cutting in fractured carbonate formation layers. This optimization helped the team to successfully complete the 1st high angle coring operation offshore in the United Arab Emirates. This case study shares the value of offset wells data for coring jobs to reduce the risk of core jamming, optimize core recovery and reduce wellbore collision risks. It also details BHA design decisions(4"core barrel, core head, low flow rate MWD tool and appropriate coring parameters), all of which led to a new record of cutting 1295 ft core in a carbonate formation with almost 100% recovery on surface.

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.

Identification of Failure Modes Under Design Extension Conditions

2015 ◽  
Author(s):  
Naoto Kasahara ◽  
Izumi Nakamura ◽  
Hideo Machida ◽  
Hitoshi Nakamura ◽  
Koji Okamoto
Keyword(s):  
High Temperature ◽  
Nuclear Power ◽  
Failure Modes ◽  
Low Cycle Fatigue ◽  
External Pressure ◽  
Lessons Learned ◽  
Local Failure ◽  
Severe Accident ◽  
Mitigation Measures ◽  
Loading Mode

As the important lessons learned from the Fukushima-nuclear power plant accident, mitigation of failure consequences and prevention of catastrophic failure became essential against severe accident and excessive earthquake conditions. To improve mitigation measures and accident management, clarification of failure behaviors with locations is premise under design extension conditions such as severe accidents and earthquakes. Design extension conditions induce some different failure modes from design conditions. Furthermore, best estimation for these failure modes are required for preparing countermeasures and management. Therefore, this study focused on identification of failure modes under design extension conditions. To observe ultimate failure behaviors of structures under extreme loadings, new experimental techniques were adopted with simulation materials such as lead and lead-antimony alloy, which has very small yield stress. Postulated failure modes of main components under design extension conditions were investigated according three categories of loading modes. The first loading mode is high temperature and internal pressure. Under this mode, ductile fracture and local failure were investigated. At the structural discontinuities, local failure may become dominant. The second is high temperature and external pressure loading mode. Buckling and fracture were investigated. Buckling occurs however hardly break without additional loads or constraints. The last loading is excessive earthquake. Ratchet deformation, collapse, and fatigue were investigated. Among them, low-cycle fatigue is dominant.

Complex Stimulation Approach to Low-Temperature Carbonate Formation Revitalizes Bahrain Brownfield

2021 ◽  
Author(s):  
Ahmed AlJanahi ◽  
Sayed Abdelrady ◽  
Hassan AlMannai ◽  
Feras AlTawash ◽  
Eyad Ali ◽  
...  
Keyword(s):  
Low Temperature ◽  
Oil Recovery ◽  
Mesh Size ◽  
Lessons Learned ◽  
Laboratory Research ◽  
Fracture Width ◽  
Field Development ◽  
Fracture Length ◽  
Carbonate Formation ◽  
Formation Pore Pressure

Abstract Carbonate formations often require stimulation treatments to be developed economically. Sometimes, proppant fracturing yields better results than acid stimulation. Carbonates are seldom stimulated with large-mesh-size proppants due to admittance issues caused by fissures and high Young’s modulus and narrow fracture width. The Magwa formation of Bahrain’s Awali brownfield is a rare case in which large treatments using 12/20-mesh proppant were successful after the more than 50 years of field development. To achieve success, a complex approach was required during preparation and execution of the hydraulic fracturing campaign. During the first phase, the main challenges that restricted achieving full production potential in previous stimulation attempts (both acid and proppant fracturing) were identified. Fines migration and shale instability were addressed during advanced core testing. Tests for embedment were conducted, and a full suite of logs was obtained to improve geomechanical modeling. In addition, a target was set to maximize fracture propped length to address the need for maximum reservoir contact in the tight Magwa reservoir and to maximize fracture width and conductivity. Sufficient fracture width in the shallow oil formation was required to withstand embedment. Sufficient conductivity was required to clean out the fracture under low-temperature conditions (124°F) and to minimize drawdown along the fracture considering the relatively low energy of the formation (pore pressure less than 1,000 psi). Understanding the fracture dimensions was critical to optimize the design. Independent measurement using high-resolution temperature logging and advanced sonic anisotropy measurements after fracturing helped to quantify fracture height. As a result of the applied comprehensive workflow, 18 wells were successfully stimulated, including three horizontal wellbores with multistage fracturing - achieving effective fracture half-lengths of 450-to 500-ft. Oil production from the wells exceeded expectations and more than doubled the results of all the previous attempts. Production decline rates were also less pronounced due to achieved fracture length and the ability to produce more reservoir compartments. The increase in oil recovery is due to the more uniform drainage systems enabled by the conductive fractures. The application of new and advanced techniques taken from several disciplines enabled successful propped fracture stimulation of a fractured carbonate formation. Extensive laboratory research and independent geometry measurements yielded significant fracture optimization and resulted in a step-change in well productivity. The techniques and lessons learned will be of benefit to engineers dealing with shallow carbonate reservoirs around the world.

Lessons Learned From Freespans at Pipeline Watercourse Crossings

2020 ◽  
Author(s):  
Gerry Ferris
Keyword(s):  
Static Load ◽  
Water Velocity ◽  
Lessons Learned ◽  
Vortex Induced Vibration ◽  
Water Loading ◽  
Relevant Question ◽  
The Past ◽  
Load Limit ◽  
Pipeline Failure

Abstract Over the past 10 years inspections (site visits, boat based surveys or diver surveys) have been completed at nearly 20,000 pipeline watercourse crossings for 20 different pipeline owners. During the last 10 years there have been 721 unique locations where an exposed pipeline was found and at 213 of these locations a freespan was encountered. Only one of the freespans resulted in the failure (loss of product) of the pipeline. This record illustrates what is now become widely accepted, that pipeline exposure does not necessarily lead to pipeline failure. The record adds to this, pipeline freespan does not necessarily lead to failure. This highlights that the relevant question for “water loading caused pipeline failure” is: Does the combination of freespan length and water velocity exceed a combination that would lead to vortex induced vibration or the exceedance of the static load limit of the pipe?

Sign in / Sign up

Export Citation Format

Share Document