Learn more about training courses being offered. Learn more about training courses being offered. This course covers the fundamental principles concerning how hydraulic fracturing treatments can be used to stimulate oil and gas wells. It includes discussions on how to select wells for stimulation, what controls fracture propagation, fracture width, etc., how to develop data sets, and how to calculate fracture dimensions. The course also covers information concerning fracturing fluids, propping agents, and how to design and pump successful fracturing treatments. Learn more about training courses being offered. Current and future SPE Section and Student Chapter leaders are invited to engage and share. Every attendee leaves energised with a full list of ideas and a support network of fellow leaders. Those sections and student chapters actively participating in this workshop have consistently been recognized with awards as the best in SPE. SPE Cares is a global volunteering drive aimed at promoting, supporting and participating in community services at the SPE section and student chapter’s level. On its official launch this year at ATCE Dubai, SPE Cares will conduct a “Give a Ghaf” Tree Planting Programme to help preserve Ghaf’s cultural and ecological heritage. The Ghaf tree is an indigenous species, specific to UAE, Oman and Saudi Arabia. It is a drought tolerant, evergreen tree that can survive a harsh desert environment. The initiative not only aims to hold events/activities at ATCE, but also recognise community service that SPE members are already conducting in their respective student chapters and professional sections. The KEY Club, open daily, is an exclusive lounge for key SPE members. The lounge is open to those with 25 years or more of continuous membership, Century Club members, current and former SPE Board officers and directors, Honorary and Distinguished Members, as well as this year’s SPE International Award Winners and Distinguished Lecturers. DSATS (SPE’s Drilling Systems Automation Technical Section) will hold a half-day symposium featuring keynote presentations on urban automation. This symposium will explore technologies being used in developing smart cities through the automation of their infrastructure, transportation systems, energy distribution, water systems, street lighting, refuse collection, etc. These efforts rely on many of the same tools needed for drilling systems automation yielding increased efficiencies, lower maintenance and reduced emissions. Their knowledge and experience can guide the path being travelled by the oilfield drilling industry.
Since the last event held in Thailand in 2014, the industry has altered significantly. Evolving challenges such as oil price volatility, the "big crew change", and digital disruption, require new approaches in applying business models and technologies to achieve cost and operational efficiencies, whilst meeting stakeholders' expectations to preserve the core business and, at the same time, stimulate progress by exploring challenges, successes, and strategies to create a fit-for-purpose set of tools, systems, models, technologies and capabilities that will reshape the industry for a smart and sustainable future. Complete MPD Rigs: Is this the Future? As the petroleum industry recovers from market lows and business recovers, we ask ourselves, what is next? This panel session shall discuss these and other appropriate topics including: - Rig utilisation forecasts - Regions for future growth - Rig types for expansion: Land, shelf, deep or ultra-deep water - Rig retirements, cold vs warm stacking and reactivation - Shipyard activity: Upgrades vs new build construction - New technologies in rig components or service delivery - Data management and work processes -Partnerships between drilling contractors and drilling service providers The industry's needs to position for recovery and forecasting is an integral component in the planning for next phase.
Green fields today mostly can be regarded as marginal fields and successfully developed. It covers the complete assessment of the oil and gas recovery potential from reservoir structure and formation evaluation, oil and gas reserve mapping, their uncertainties and risks management, feasible reservoir fluid depletion approaches, and to the construction of integrated production systems for cost effective development of the green fields. Depth conversion of time interpretations is a basic skill set for interpreters. There is no single methodology that is optimal for all cases. Next, appropriate depth methods will be presented. Depth imaging should be considered an integral component of interpretation. If the results derived from depth imaging are intended to mitigate risk, the interpreter must actively guide the process.
Africa (Sub-Sahara) Cairn Energy has flowed oil from its SNE-2 well offshore Senegal. Drillstem testing of a 39-ft interval achieved a maximum stabilized but constrained flow rate of 8,000 B/D of high-quality pay. A flow rate of 1,000 B/D of relatively low-quality pay was achieved from another zone. Drilled to appraise a 2014 discovery, the well lies in the Sangomar Offshore block in 3,937 ft of water 62 miles from shore. Drilling reached the planned total depth of 9,186 ft below sea level. Cairn has a 40% interest in the block with the other interests held by ConocoPhillips (35%), FAR (15%), and Petrosen (10%).
Africa (Sub-Sahara) Kosmos Energy has made a significant deepwater gas discovery off Senegal. The Guembeul-1 well in the northern part of the St. Louis Offshore Profond license in 8,858 ft of water encountered 331 net ft of gas pay in two excellent-quality reservoirs, the company reported. The results demonstrate reservoir continuity and static pressure communication with the Tortue-1 well, which suggests a single gas accumulation. The mean gross resource estimate for the Greater Tortue complex has risen to 17 Tcf from 14 Tcf as a result of the Guembeul discovery, the company said. Kosmos, the operator, has a 60% interest in the well. Timis (30%) and Petrosen (10%) hold the remaining interest. In Salah Gas has started production from its Southern fields in Algeria.
Acid stimulation in sandstone reservoirs containing significant amount of clays can end up with undesired results due to unexpected reactions between stimulation fluids and formation clays. This paper demonstrates how heavily damaged clay-rich sandstone reservoir completed with cased hole gravel pack (CHGP) in offshore Myanmar can be successfully established for commercial production with organic clay acid stimulation treatment. The formation is laminated dirty sand with very high clay content (up to 30%) and large gross height (>100m MD). Production logging results showed only a small portion of perforated intervals contributing to production. Thus, an appropriate stimulation treatment is required to unlock well potential and prevent screen failures from concentrated flow through a small interval.
Given high clay content as well as presence of acid sensitive clays, conventional treatments using HCl as preflush and hydrofluoric (HF) acids as main fluids would result in potential damages from secondary and tertiary reactions. Furthermore, undissolved clays in the critical matrix left over from the treatment would potentially migrate and plug the pore throat. The new acid system was designed to generate small amount of HF in-situ (~0.1%) at any given time with total strength of 1% HF, which would greatly minimize second and tertiary reactions and also permits acids travel deeper into the formation. Furthermore, the reaction products would react with the clays and physically "welding" the undissolved clays to the surface of the pore spaces permanently and prevent them from migration.
The treatment was designed in three stages: 1) screen and gravel pack cleanup using coiled tubing (CT) jetting; 2) injectivity test; 3) main treatment consisting of acetic acids as preflush, and new acid system as main fluids followed by overflush. A newly designed linear gel containing relative permeability modifier was used for diversions. Two underperforming CHGP wells were treated, and both wells yielded 100% increase in productivity with no fine production observed at the surface.
The success of the campaign owes to the sophisticated engineering workflow which starts from diagnostic of the damage zone and root-cause of the formation damage, followed by detailed analysis of various skin components using radial numerical reservoir modeling for all the reservoir layers that led to a proper treatment strategy and fluid design based on the damage and formation mineralogy as well as comprehensive laboratory tests. This has helped to minimize the risk of the treatment and eventually unlocked the production from the heavily damaged sandstone reservoir.
This paper provides technical feedback of a successful use of Directional Casing While Drilling (D-CwD), a technique allowing to simultaneously drill and case the hole while following the directional plan. It highlights how substantial gains were realized on Badamyar project in Myanmar, having benefited from the D-CwD technique to optimize the architecture.
The Badamyar development campaign involved the drilling of four horizontal gas wells in conventional offshore environment in Myanmar. Other regional wells had already experienced wellbore issues to get the 13 3/8″ casing vertically to 450m. On Badamyar, drilling directly with the casing allowed to minimize operational exposure to losses and wellbore instability, and to achieve the challenge to get the 13 3/8″ to 800m and 45deg inclination, avoiding the requirement for an additional surface casing.
All four 13 3/8" sections were successfully directionally casing-drilled and cemented in fourteen days within budget duration, which, despite the additional complexity, is comparable to the best performance in the block in the last twenty years. The average Rate of Penetration was 30 m/hr, same as fastest conventional case in the field, without mentioning the huge advantage that when reaching the required depth, the casing is already in the hole. Indeed, once the casing has reached the required depth, drill pipe is run inside the casing to unlatch and recover the directional BHA, and pull it back to surface, leaving the casing in place ready for the cement job. While conventionally, casing still needs to be run with associated time and risks (losses, wellbore stability, stuck casing, accidental side-track, etc…).
This Directional-CwD was a new concept to most of the teams involved: Operator, Rig contractor and Tubular Running Services. It required changing the "hundred and thirty years of conventional drill-pipe drilling" mindset. This paper describes the decision making process to switch from conventional to casing-drilling, the preparation phase where risks were identified and mitigated, as well as the excellent operational results.
This paper, by presenting a successful first implementation within a major O&G company, brings to the drilling industry an additional case that the system works, is technically fit-for purpose, cost effective, and has the tremendous potential to replace conventional drilling in several applications. It also highlights some potential limits and opportunities for optimization which should be considered for further development (trajectory constraints, fatigue life and well control).
The recent major seismic events in South East Asia have led the Oil & Gas Companies to reevaluate the design of their offshore platforms with sometimes more stringent seismic conditions than original ones. The Yadana offshore platforms located in a high seismic activity area in the Andaman Sea, operated by TOTAL E&P MYANMAR, were part of this important work. DORIS Engineering and GDS have developed specific seismic analyses to validate the design under new conditions.
This paper will present the different engineering challenges which were faced to revalidate the structural integrity of the different jacket type platforms under new seismic conditions. It will describe the methodology specifically developed for this project and how were identified and defined the necessary site modifications. These analyses were developed to assess more accurately the maximum relative displacements of jacket type platforms connected by bridges and to validate the stresses in foundation piles. It will also address the offshore works performed on the platforms with a maximization of SIMOPS works and limited shut down periods.
Insufficiencies in the conventional design approach required to develop specific methods to validate the integrity of the jacket foundations and the platforms displacement (bridges). This paper will address, in particular, the design methodology used to verify the integrity of the jacket foundations and to define the required topsides and jacket reinforcements. A time domain approach, based on the "ASN" guidance used for nuclear facilities, was developed to verify the pile stresses and assess more accurately the maximum relative displacement of the platforms connected by bridges. The offshore works were afterwards performed in a timely and cost-effective manner. The detail engineering and the operation offshore had to include risky and unconventional operation such as bridges pot bearings replacement or piping modifications on bridges. SIMOPS works were maximized allowing the shutdown to be limited to the shortest duration.
This paper presents the different engineering challenges which were faced to revalidate the design of existing platforms. It presents the specific methods which have been successfully developed by engineering to validate the design. This project is a good example of a "brownfield" project, from a challenging situation through development of a reliable and efficient engineering solution to successful completion of offshore works.
Wongkamthong, Chayut (PTT Exploration And Production Public Co., Ltd.) | Wongpattananukul, Kongphop (PTT Exploration And Production Public Co., Ltd.) | Suranetinai, Chaiyaporn (PTT Exploration And Production Public Co., Ltd.) | Vongsinudom, Varoon (PTT Exploration And Production Public Co., Ltd.) | Ekkawong, Peerapong (PTT Exploration And Production Public Co., Ltd.)
Several gas fields in South East Asia share some common traits among them, obviously on their geological features but also on their complex field operation. With a large number of small gas accumulations spreading across a large area with high degree of lateral compartmentalization, production from these fields are usually accomplished by hundreds of wells through multi-branches field networks. The scope of this paper is to present the challenging journey of the company's in-house innovative methodology which resulted in the development of a robust software to address the above challenges. The main objective of the software is to optimize field production under numerous constraints present in these fields.
With the target to optimize field production and enhance predictive capability, the company integrates the experiences from operating several fields and proposes an innovative approach to tackle these field management challenges. The resultant software optimizes and solves the network calculation by simplifying and formulating the production network into a system of linear equations, then applying optimization techniques as large-scale simplex and mixed-integer linear programming algorithms, to search for the best production scheme while taking user-selected objective function into consideration. The workflow was developed using MATLAB optimization toolbox to work in conjunction with a familiar Excel-formatted input. Moreover, with the incorporation of the Decline Curve Analysis (DCA), it is also applicable for generating long term production forecast. The tool was further combined with Production Data Management System (PDMS) to provide a more efficient automated workflow. It was used to maximize condensate production in Arthit field, where the main constraints are to capture the production loss from CO2 removal unit and to limit mercury concentration in sales condensate. While, in Zawtika field, the application exploits quadratic programing to minimize the sum of gas production rate square hence controlling wells to produce at optimal rate, mitigating sand production problem.
In this paper, successful implementation examples and benefits gained will be discussed. It ensures that the condensate production in Arthit field is kept at optimal level compared with about 91% efficiency when subjected to conventional practices while, in Zawtika, applying the workflow and operation resulted in dramatically lower sand production problem. For future forecast, a look-back study was performed to make sure that the method of calculating future potential is accurate. Not only does this new tool provided a more efficient way for the teams to manage their assets but, more importantly, it also helps to save costs by reducing man-hours through its rapid computation.
This paper highlights the top quartile performance well delivery of Yetagun In-fill Phase 6 drilling campaign in Yetagun gas field, offshore Myanmar. Drag, Torque, Hook load and Stand Pipe Pressure that occur in an ERD well is typically higher than conventional well due to long horizontal displacement and high lateral inclination angle. Hence, the importance of planning process, execution, drilling practices and lesson learnt which essentially resulting in a successful drilling operation were discussed in the paper.
PETRONAS Carigali Myanmar Limited (PCML) successfully drilled three in-fill wells: YA-01, YA-05, and YA-12ST1 which were classified as ERD based on extended reach industry experience plot with the objective to maintain the gas production rate. Excellent planning process and good teamwork among the project team members were required to tackle all the technical issues as well the environmental and logistical challenges. The unique and challenging design for YA-05 as compared to others where it has the longest tangent length which fall within 70-80° sail angle. YA-01 and YA-12ST1 were classified as ERD medium reach class design, thus require specific ERD drilling, hole cleaning, ECD monitoring, tripping and backreaming practices to ensure success of the well. The challenges in designing ERD wells were multiple such as high torque and drag, loss circulation, well collision, differential sticking, borehole instability, hole cleaning, longer open hole interval, high stand pipe pressure and high temperature. YA-12ST1 well was planned with sidetracking design utilizing whipstock and hence, tortuous wellpath which leads to high dogleg at the sidetrack point need to be considered. Losses of circulation were observed from historical development campaign of the field. Thus it was essential that extra precautions have been prepared for efficient hole cleaning and consistent penetration control. Other challenges attached with the recommended practices to overcome them including wellbore instability, differential sticking, drag and friction factors were analyzed further in this paper.
In conclusion, this paper serves as a reference for future ERD well planning and execution as the overall drilling campaign achieved excellent well delivery performance in term of cost and time. This campaign has been successfully completed with remarkable achievements such as the first semi-submersible tender-assisted drilling rig used by PETRONAS group, huge total cost saving, zero lost-time injury, and successfully secured the reservoir target and meet the gas volume target.
The novelty of the successful Yetagun Phase VI development wells project yielded good practices, technology used and excellent project planning that can be applied in future projects. This paper also can be a reference for future ERD well drilling in Myanmar.