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Collaborating Authors
IADC/SPE Asia Pacific Drilling Technology Conference
Abstract Well design is a process to integrate multiple designs objects, such as trajectory, wellbore geometry, BHA and drillstring, fluid, and rig specification to work synergically to deliver a successful drilling execution. The method to validate coherency of those various design objects is by performing engineering analysis through modeling, such as torque and drag, hydraulic, vibration, and casing load analysis. Every time any design objects are changed, the engineer needs to rerun engineering analysis calculations to ensure the proposed changes are still acceptable or within equipment specification and design standards. Engineers also need to define the most optimal parameters and designs in order to get the best performance in execution. For this purpose, the engineer spends time performing engineering sensitivity analysis to understand the effect of various parameters on the design KPIs. The challenge with the current drilling engineering application is that engineers need to perform multiple scenarios manually, which is very cumbersome and time-consuming. Time requirements will limit the engineer to perform different kinds of scenarios. Comparing and visualizing the analysis results of multiple scenarios also can be difficult, especially where they involve multiple dimensions. Novel ideas or solutions were introduced in the cloud-based new digital well construction planning applications. The system will automatically create multiple scenarios based on the number of sensitivity parameters. For example, calculating the sensitivity of hydraulic calculation for 5 different flowrates, 5 RPMs, 5 fluid densities, and 5 ROPs will produce 625 scenarios. And each scenario will be calculated for every 100 ft from run start depth to run end depth. All those will be calculated with the power of cloud computation to speed up simulation time and the results stored in the data cube, which is available for business intelligence tools to visualize it. Leveraging the latest development of data visualization technology also brings a new way for an engineer to view multidimensions of plots to quickly get the insight for decisions. This new method of sensitivity analysis and visualization will improve drilling engineer working efficiency to identify potential risks and formulate the optimal parameters for the drilling program. The engineer can easily interact with the plots and understand the effect of multiple parameters on the engineering simulation results. This will give a new user experience for drilling engineers on evaluating drilling engineering sensitivity analysis results and plots in the new digital way of working.
- Information Technology > Data Science > Data Mining (0.69)
- Information Technology > Visualization (0.69)
Abstract Applying bridging agents to prevent seepage losses is a common practice during drilling reservoir sections which limits the invaded zone and reduces stuck pipe possibility. Unfortunately, the initial particle size distribution (PSD) design of bridging agents based on static models does not prevent actual seepage losses due to the induced fractures which have different sizes comparing to the initial reservoir pore sizes. This paper reviews an actual case study with provided solutions in an offshore field located in the Middle East which had a seepage loss circulation problem through induced fractures. It also presents analyzing natural and induced fractures size of the reservoir layer to choose optimized possible bridging agents’ PSD to cure/prevent loss circulation problems. The maximum/average pore size of formation can be measured from routine core analyses. A geological method to estimate the induced fracture widths with geo-mechanical data were used. Finally, optimum blends of bridging agents for loss circulation pills or background treatment to prevent mentioned problems were designed. Based on the laboratory testing on cores taken from previously-drilled wells in the mentioned field, the maximum size of pore throats was measured as 20 microns. Therefore, using the Ideal Packing Theory (IPT) method, the result for selecting bridging agents through pore throats (for seepage loss) indicates that optimum treatment is using of bridging agents with D50 and D90 6.5 and 16 microns, respectively. Also, for improving the treatment selection through parameters such as PSD of bridging agents, investigation on behavior of fracture growth were done. As a result, induced fracture width in studied well, with provided geo-mechanical (such as Poisson's Ratio & Young Modulus) and drilling fluid data was calculated approximately to be 230 microns through the porous medium in the near-wellbore region. Therefore, optimization for bridging these new fractures while drilling was performed again and it was concluded that optimum bridging agent size distribution at the tip of these newly-created induced fractures is applying bridging agents with D50 and D90 of 64 and 170 microns respectively, which are approximately 10 times higher than normal treatment in size. This paper describes the historical seepage circulation and related problems in the mentioned field and presents a methodology to prevent these issues by predicting induced fractures and optimizing bridging agent PSD to block them. Considering this methodology, the gap between the design and actual drilling is reduced and both rig downtime and related drilling and drilling fluids costs can be saved.
- Asia (0.67)
- North America > United States (0.47)
Abstract This paper presents an integrated workflow for feasibility study of cuttings reinjection (CRI) based on 3D geomechanics analysis. Solutions of various mechanical variables obtained with 3D geomechanics analysis at various level of scale are used as basis for designing parameters of CRI. Solutions of geomechanics analysis provide basis for a feasibility study and/or design of CRI: solution of 3D geostress distribution and the effective stress ratio are the essential factors for selecting the best location of injection well; solution of 1D geomechanics analysis provides basis for choice of true vertical depth (TVD) interval for injection sections; and hydraulic fracturing performed in the framework of 3D geomechanics analysis provides the most accurate solution for both the injection pressure window and fault reactivation related to CRI as well as estimation of seismic behavior. Example of feasibility study of cuttings reinjection with the integrated workflow proposed here is presented with data from a case in offshore West Africa. Solutions of geomechanics analysis are used for decision making at various stages of CRI. There are several faults in this region. The location of the injection well is chosen at a place with principal stress ratio's value at 0.68. The interval of injection well section is chosen as a 140-ft section with center at TVD = 6,700 ft. The numerical solution of injection pressure window is defined with 46 MPa as lower bound and 80 MPa as upper bound. The width of the fracture is 0.069 m, and length and height are 4,000 m and 100 m respectively. The accommodation volume of fluid with cuttings is 2.76×104 m3. The maximum magnitude of Richter scale of the seismicity corresponding to the fault reactivation is 3.15. The case study described in this paper provides an integrated workflow for feasibility study of CRI based on 3D geomechanics analysis. A best practice for this type of CRI design is also presented.
- Asia > Middle East > Saudi Arabia (0.46)
- North America > United States > California (0.28)
- Geology > Structural Geology > Tectonics > Plate Tectonics > Earthquake (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
Abstract Cementing is one of the sequences in the drilling operations to isolate different geological zones and provide integrity for the life of the well. As compared with oil and gas wells, geothermal wells have unique challenges for cementing operations. Robust cementing design and appropriate best practices during the cementing operations are needed to achieve cementing objectives in geothermal wells. Primary cementing in geothermal wells generally relies on a few conventional methods: long string, liner-tieback, and two-stage methods. Each has challenges for primary cementing that will be analyzed, compared, and discussed in detail. Geothermal wells pose challenges of low fracture gradients and massive lost circulation due to numerous fractures, which often lead to a need for remedial cementing jobs such as squeeze cementing and lost circulation plugs. Special considerations for remedial cementing in geothermal wells are also discussed here. Primary cement design is critical to ensure long-term integrity of a geothermal well. The cement sheath must be able to withstand pressure and temperature cycles when steam is produced and resist corrosive reservoir fluids due to the presence of H2S and CO2. Any fluid trapped within the casing-casing annulus poses a risk of casing collapse due to expansion under high temperatures encountered during the production phase. With the high heating rate of the geothermal well, temperature prediction plays an important part in cement design. Free fluid sensitivity test and centralizer selection also play an important role in avoiding mud channeling as well as preventing the development of fluid pockets. Analysis and comparison of every method is described in detail to enable readers to choose the best approach. Massive lost circulation is very common in surface and intermediate sections of geothermal wells. On numerous occasions, treatment with conventional lost-circulation material (LCM) was unable to cure the losses, resulting in the placement of multiple cement plugs. An improved lost circulation plug design and execution method are introduced to control massive losses in a geothermal environment. In addition, the paper will present operational best practices and lessons learned from the authors’ experience with cementing in geothermal wells in Indonesia. Geothermal wells can be constructed in different ways by different operators. In light of this, an analysis of different cementing approaches has been conducted to ensure robust cement design and a fit-for-purpose cementing method. This paper will discuss the cementing design, equipment, recommendations, and best available practices for excellence in operational execution to achieve optimal long-life zonal isolation for a geothermal well.
- Asia (0.49)
- North America > United States (0.46)
Innovative Approach Lead to Best in Class Development Campaign Drilling and Sand Control Completion, Myanmar Offshore
Follett, Meth (PTT Exploration and Production PCL) | Pensook, Teerapat (PTT Exploration and Production PCL) | Piyakunkiat, Nuttapon (PTT Exploration and Production PCL) | Benjaboonyazit, Veerawit (PTT Exploration and Production PCL) | Nopsiri, Noppanan (PTT Exploration and Production PCL)
Abstract The operator relentlessly thrives for the minimum well construction cost. Continuous improvement and Innovative approach are the major drives for developing the marginal gas field, Myanmar offshore. Whereas, routine and consistent operations may mask up the operator and leave out many rooms for improvement from operation excellence during the development phase of the project life cycle. PTTEPI successfully started up the second development campaign, Myanmar offshore in early 2016. Since then the team has brought up many ideas to continuously improve the operation and achieve milestones for both safety and performance. This paper will share the best in class for well construction of Myanmar offshore on well design, drilling engineering, rig selection, offline utilization, drilling and sand control practices and fit for purpose procedures. The performance is significantly improved on both drilling and sand control operation which results in total days per well reduction over 50% and 80% for drilling operation and sand control operation respectively. Total days per well for drilling performance on the last platform in 2019 is reduced to 4 days per well compared to 9 days per well when the first development platform was drilled in 2013. Sand Control performance is improved further. Total days per well for Sand Control performance on the last platform in 2019 is reduced to 3.5 days per well (dual-zone completion) compared to 18 days per well when the first development platform was completed in 2013. Recommended practices and well designs are shared as a case study of drilling and sand control operation for Myanmar offshore development. This can be a guideline for another operator to develop oil and gas field offshore Myanmar.
- Well Drilling (1.00)
- Well Completion > Sand Control > Sand/solids control (1.00)
- Well Completion > Completion Selection and Design > Completion equipment (1.00)
Use of Micronized Weighting Agents for High Density Completion Fluids: A Case Study
Deshmukh, Sufyan (M-I SWACO, A Schlumberger Company) | Motta, Marcelo Dourado (M-I SWACO, A Schlumberger Company) | Prabhudesai, Sameer (M-I SWACO, A Schlumberger Company) | Patil, Mehul (M-I SWACO, A Schlumberger Company) | Kumar, Yogesh (M-I SWACO, A Schlumberger Company) | Mihalic, Blake Anthony (M-I SWACO, A Schlumberger Company) | Dey, Rahul Sukanta (Schlumberger)
Abstract A unique invert emulsion fluid (IEF) weighted up with treated micronized weighting agent (MWA) slurries has been developed and successfully implemented in the field as a completion and testing fluid. The utilization of this unique IEF by design allowed the fluid properties to be lower on viscosity and superior suspension characteristics, which allowed for thermally stable fluid and provided excellent downhole hydraulics performance. Much of the earlier development and deployment of this type of IEF was focused on drilling for sections in narrow mud weight and fracture gradient windows, coiled tubing operations, managed pressure drilling, and extended reach wells. Many of these drilling challenges are also encountered in high pressure and high temperature (HTHP) and ultra-deepwater field developments and mature, depleted fields. Early fluid developments focused on designing the fluids chemistry and physics interactions and the optimization of mineralogy of the weighing agent used. There was also some concern on variability of the results seen on the return permeability as well as standard fluid loss experiments. The paper describes the laboratory and field and rigsite data generated while using the MWA in IEFs during completion operations with a client in India. The paper will briefly describe the laboratory work before the application and the associated results observed on the rig site. It will also outline all the challenges which were faced during the execution and mixing of the MWA IEFs. Each separate operation required a high-density reservoir fluid solution above 15.5 ppg [1.85 sg]. Because corrosion, sag potential, and scale were the operator's main concerns, a solids-free brine or other type of weighting agent (for e.g. Calcium Carbonate and/or Tri-Manganese Tetra Oxide) solution was not favored. A high-density IEF designed with MWA allowed us to provide a solution that mitigated against the risks identified in each operation. The thin viscosity profile enabled completion activities to proceed with minimal fluid consumption at surface, reducing the overall environmental impact. The high-density (15.6 ppg [1.86 SG] and 16.2 ppg [1.94 SG]) invert emulsion fluid was designed to minimize sag potential with minimal reservoir damage potential. With a thinner viscosity profile compared to conventional IEFs at equivalent densities, the fluid enabled completion activities with minimal fluid volumes lost over shakers and reduced the environmental impact. The MWA that was used to build the IEF used for drilling and completion fluid enabled maintenance of extremely low-shear rate viscosities when compared to conventional barite-laden fluids. This fluid was used for suspending and abandoning the well in Case Study A, where the reentry and intervention of the well was planned to be after 2 years. After exposure of the fluid in Case Study A, the fluid showed minimum sag after re-entry of the well and the intervention activities were done without any problems. Case Study B showed that the fluid was mixed to the density of 16.2 ppg and was used to perforate and test two different zones. The bottom hole static temperature (BHST) reported were 356 degF (180 degC) for Case Study A and 376 degF (191 degC) for Case Study B respectively. The paper attempts to show the effects of using this alternative weighing agent as a completion fluid instead of a high-density solids-free brine or other solids-laden high-density brines and the associated success, which could be managed if the fluid design is carefully planned.
- Europe > Norway > North Sea > Northern North Sea > East Shetland Basin > PL 193 > Block 34/11 > Kvitebjørn Field > Statfjord Group (0.99)
- Europe > Norway > North Sea > Northern North Sea > East Shetland Basin > PL 193 > Block 34/11 > Kvitebjørn Field > Cook Formation (0.99)
- Europe > Norway > North Sea > Northern North Sea > East Shetland Basin > PL 193 > Block 34/11 > Kvitebjørn Field > Brent Group (0.99)
- (2 more...)
A Spectacular Cementing Record in Myanmar Offshore Deepwater Well
Sun, Gang (COSL) | Ullah, Mohammad Solim (COSL) | Li, Yi (COSL) | Maheshwari, Mukesh (PTTEP) | Khumtong, Thirayu (PTTEP) | Xiong, Shao Chun (COSL) | Ai, Wu Chang (COSL) | Balaraman, Balasundaram (COSL) | Edward, Mic Mac (COSL) | Chen, Feng (COSL) | Yao, De Gang (COSL)
Abstract Myanmar offshore is considered to be a very promising exploration and production (E&P) location for oil and gas but poses significant challenges to drilling and cementing operations. Low temperature at sea bed delays the cement compressive strength development, High pore pressure with steep gradient and low fracture pressure created a very narrow drilling margin, presence of shallow flow in riser-less section further complicated the cementing operation, low density cement with high performance is a must. With the exorbiant cost of Deepwater drilling, much needed fit for purpose cementing technology with efficient logistic support and excellence in execution became crucial. This paper elaborates the cementing challenges at different sections of a recent deep-water well in offshore Mynamar and techniques that were planned and used to address those challenges. This paper will describe in detail the cementing method, how it fit the well situation, how the cement slurry was designed then evaluated and how the logistic support and execution were carried out, resulting in a resounding success.
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.69)
- Geology > Geological Subdiscipline (0.50)
Valuable Cuttings-Based Petrophysic Analysis Successfully Reduces Drilling Risk in HPHT Formations
Chen, Jianlin (CNPC Xinjiang Oil Field Co.) | Yao, Yanhua (Baker Hughes Company) | Liu, Yingbiao (CNPC Xinjiang Oil Field Co.) | Wang, Zhaofei (CNPC Xinjiang Oil Field Co.) | Collier, Craig (Baker Hughes Company) | Tang, Wenhuan (Baker Hughes Company)
Abstract Cuttings data has always been neglected or forgotten as a source of information by many operators. In some areas, it is even common practice to throw away cuttings in order to reduce cost. However, cuttings data can yield a great amout of information to provide great value and support to drilling operations, as well as reduce potential downhole risks. This was evident in wells drilled in remote Western regions of China, where wells typically have high temperature high pressure (HTHP) formations with a true vertical depth ranging between 4000-7000 meters and target formation temperature between 150-160 degrees Celcius. Due to severe drilling conditions, the measurement tools of Logging While Drilling (LWD) and Measured While Drilling (MWD) are at high risk of running into holes. Even due to the high formations’ temperatures is over the bottom line of LWD and MWD tools, the sensors of LWD and MWD cannot work efficiently in such circumstances, increasing the drilling risk and expense. Thus, "blind" drilling is the most reasonable economical choice for local operators. Without sufficient real-time formations’ information, the drilling uncertainties dramatically increase. The fluid loss, pipe stuck, as well as drilling bit damages frequently occur. Currently, there is no successful well that accesses to the target reservoir. The data from the wireline logs and cores cannot be available, as the well is the first exploration well in the block; however, during drilling, only drill cuttings are available for peoples. The creative cutting-based petrophysics models are built for the formation analysis that is able to provide rock density, cuttings gamma, Delta Time of Compressional Acoustic (DTC), Unconfined Compressional Strength (UCS) Index, Caliper Index, Brittleness Index, and Hydrocarbon Index from the cuttings samples at the wellsite on a near-real-time basis. This data can help people quantitatively and qualitatively evaluate the downhole formations on a near-real-time basis and can help people to make a more reasonable decision, and therefore, reduce the drilling risk within a controlled level. The authors provide the several cases to study the cutting models into drilling events, and proves the models are consistent with log and core data, and match the drilling parameters and like ROP, and pumping pressure, as well as torque, and bit performance. LWD and MWD are unable to run into the hole due to high formation pressure and extreme risky hole. The field portable XRF instrument is applied, and the mineralogy and elements input into the models. The cuttings petrophysics analysis application can provide the valuable information for drilling engineers to drill the wells to TD.
- Geology > Mineral (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
Abstract Multilateral wells have been proven over decades and have developed into a reliable and cost effective approach to mature field rejuvenation and extended commercial viability. This paper will discuss case studies demonstrating a number of techniques used to create infill multilateral wells in existing fields with a high level of reliability and repeatability. Techniques reviewed will cover cutting and pulling production casing to drill and case a new mainbore versus sidetracking and adding laterals to an existing mainbore. Discussion will also cover completion designs that tie new laterals into existing production casing providing significantly greater reservoir contact. Temporary isolation of high water-cut laterals brought into production later in the well's life through bespoke completion designs will also be discussed. Case studies will include discussion of workover operations, isolation methods, and lateral creation systems. Where available, resulting field performance improvements will also be discussed. In Norway, slot recoveries are commonly performed by cutting and pulling the 10-3/4" casing, redrilling a new mainbore, and running new casing. This enables junction placement closer to unswept zones and easier lateral drilling to targets. It does have drawbacks, however, related to the additional time required to pull the subsea xmas tree and challenges associated with pulling casing. In 2019, Norway successfully completed a 10-3/4" retrofit installation, whereas a sidetrack was made from the 10-3/4" and an 8-5/8" expandable liner was run down into the reservoir pay zone where two new laterals were created. The 8-5/8" liner saved time otherwise spent having to drill the section down to the payzone from the laterals. These wells have a TAML Level 5 isolated junction, Autonomous Inflow Control Devices (AICDs) in each lateral, and an intelligent completion interface across the junction, enabling active flow management and monitoring of both branches. In Asia, infill laterals were added to existing wellbores by sidetracking 9-5/8" casing and tying production back to the original mainbore. These dual laterals were completed with intelligent completions to enable lateral flow management and monitoring of both laterals. In Australia, dual laterals were created in a similar fashion; laterals are added to existing wells; however, a novel approach was used to manage water from existing lower mainbore laterals whereby they are shut in at completion and opened later when the new lateral is watered out. The older lateral now produces at lower water cut given the time allowed for water coning in the lateral to relax. Using this practice, production is alternated back and forth between the two laterals. In the Middle East, an older well has been converted from TAML Level 4 to Level 5 in order to prevent detected gas migrating into the mainbore at the junction. This conversion of a cemented junction well has enabled production to resume on this well. The well was converted to incorporate an intelligent completion to enable flow control of each lateral. This paper intends to provide insights into the various mature field re-entry methods for multilateral well construction, and a review of the current technology capabilities and well designs through the review of multiple case histories.
- Oceania > Australia > Western Australia > North West Shelf > Carnarvon Basin > Exmouth Basin > Kangaroo Trough > Block WA-35-L > Novara Field (0.89)
- Oceania > Australia > Western Australia > North West Shelf > Carnarvon Basin > Exmouth Basin > Kangaroo Trough > Block WA-155-P1 > Novara Field (0.89)
- Oceania > Australia > Western Australia > North West Shelf > Carnarvon Basin > Exmouth Basin > Block WA-44-R > Coniston Field (0.89)
- (3 more...)
Application of Hydraulic Fracturing Candidate Selection Leading to Oil Production Boost from Multi-Layered, Low-Permeability Reservoirs: A Successful Case Study in Thailand
Wantawin, Marut (PTT E&P PLC) | Sirirattanachatchawan, Thum (PTT E&P PLC) | Suppachokinirun, Theerapat (PTT E&P PLC) | Hnuruang, Kittithuch (PTT E&P PLC) | Rongdechprateep, Sorawee (PTT E&P PLC) | Charoenniwesnukul, Kritsada (PTT E&P PLC)
Abstract Hydraulic fracturing activities implemented in Sirikit onshore oilfield of Thailand over a decade. Before 2018, the variation in post-fracturing production performance resulted in about 50% stimulation success rate. This outcome posted a big challenge to maintain project momentum. Hence, the candidate selection methodology was developed in-house which recommends "suitable" reservoirs. Using selection criteria, the multi-layered, low permeability reservoirs were selected for the 2018-19 Hydraulic Fracturing Campaign. Production analysis was conducted using the information gathered from past hydraulic fracturing campaigns. Reservoir Index (RI) was invented to distinguish the subsurface quality by formation permeability, thickness, pressure, and fluid properties. Together with the Fold of Increase (FOI) owing to hydraulic fracturing, a performance-based relationship was created which can categorize suitable reservoirs based on their RI ranges. This method has been applied to newly drilled wells during 2018. In the end, there were 13 wells selected to perform 28 hydraulic fracturing stages. The 2018-2019 Hydraulic Fracturing Campaign at Sirikit Oilfield was planned and executed. Post-fracturing production tests showing significant improvement. Some wells resulted in excellent oil production rate naturally, while some maintained high rate by artificial lift. According to post-campaign analysis, hydraulic fractures were proved to connect multiple layers of satisfactory flow capacity. In addition, well angle and stress direction accommodated the placement and orientation of multiple hydraulic fractures. As a result, the number of hydraulic fracturing stages that achieved economic production tests improved to 75% success rate. Hydraulic fracturing results from the past were fully utilized in order to achieve sustainable production improvement, thus driving continuous stimulation activities in the future. The candidate selection methodology has shaped up a candidate selection workflow that pointed out success criteria and avoided those that may lead to failure, which proved to be successful in one of the most complex fields in Thailand.