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.
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.
For the past decade, biogenic gas production from the offshore Gulf of Moattama has significantly contributed to both the domestic and international gas market in this region. And yet, despite success in exploring for biogenic gas, our understanding of how these generative and trapping systems work, to some extent, remains a mystery.
The primary goal of our study has been to unlock the mysteries of biogenic gas generation through a review of available literature and a detailed analysis of the geology and hydrocarbon occurrence in PTTEP's Zawtika Field.
Our study began with a detailed literature review in order to develop an understanding of the fundamental mechanisms of biogenic gas generation. We realised at this point that while biogenic gas generation is a common phenomenon; trapping of such gas in commercial quantities is unusual.
Through a process of intensive lab analysis of hydrocarbons and sediments, the geochemical properties of hydrocarbon gas and potential biogenic source rocks were determined. 1D burial history modeling applying biogenic gas kinetics was conducted to determine the key parameters contributing to the Zawtika Field success case. Success case analysis outputs integrated with latest literature findings has resulted in formulation of the recipe for biogenic gas generation and accumulation.
Depositional setting appears very important in the generation and trapping of significant volumes of biogenic gas. The series of progradational packages deposited within the Ayeyarwady Delta are instrumental in establishing the source-reservoir system hosting such biogenic gas deposits. These sedimentary fluctuations dictate change in lithological character resulting in coarsening upward sediment cycles.
Extremely high deposition rates are calculated for sediments deposited through Pliocene to recent times, commonly greater than 1,000m to 2,000m/million years. Such high deposition rates are instrumental in providing the sediment overburden that allows sealing of such biogenic systems.
The Zawtika field is situated west of the termination of the Sagaing and Mergui fault systems creating NE-SW trending splays at the end of the Moattama Basin. Within this specific depositional setting, post-oxic depositional environment conditions are required. This environment of deposition is initially oxic where high sulphate content in water in the depositional system inhibits biogenic methane generation.
Post burial, reduction of sulphate to few ppm levels provides a suitable environment for biogenic methane generation. Rate of removal of sulphate vs. depositional rate will have a significant impact on depth at which biogenic gas generation occurs and therefore possibility of trapping.
Low sediment water interface temperature (SWIT) and geothermal gradient/heat flow regime are required to place the biogenic gas generation window as deep as possible. Such is required so that generation occurs for as long as possible providing time for trap formation and sealing.
Subsurface geothermal gradient or heat flow less than 3.5°C/100m and 50mW/m2 respectively is likely necessary. Bio-gas generation window depth range of between 500m to 2,000m is considered typical with generation window lengths around 1 to 1.5 million years.
Continuous delivery of humic, land derived organic matter into the depositional setting is essential. However, provision of high amounts of high quality organic matter (High Hydrogen Index (HI)) is not required for the generation process.
It appears that methane generating micro-organisms are capable of metabolising organic matter with HI as low as 50, though, HI greater than 100 to 150 appears advantageous. Typical amounts of organic matter in such sediments range from as low as 0.5 to 1%wt.
The results of our study have clearly delineated the geological and geochemical parameters that have primary influence on the successful generation and trapping of biogenic gas in the offshore Gulf of Moattama.
From this we have been able to formulate a specific biogenic gas risking index that allows us to more effectively explore for biogenic gas in this and similar geological settings. With this knowledge and methodology in mind, we consider that PTTEP is positioned as a leader in ongoing exploration for biogenic gas in S.E. Asian and other biogenic gas prone basins.
To ensure safe operations and to maximize well potential, PTTEPI has formulated a sand production management strategy to reduce risks due to sand production while extracting natural gas resources from the young clastic reservoirs formed during Plio-Pleistocene geological sequence. Over the 2 years of historical production, the strategy has been fine-tuned and enhanced to improve its effectiveness in managing sand production.
The strategy integrates efforts from both subsurface and surface disciplines. It covers initial well completion design to address the need for sand control, continuous recording and analysis of performance data after a well is put on production to monitor and manage sand production within acceptable limits, data acquisition programs to obtain additional information for analysis of sand production, and remedial and mitigation initiatives to address sand production. The following sections will discuss, in more detail, each component of the sand production management strategy.
Grant, Graham (Wiwat Pattarachupong – PTTEP International) | Soon, Lee Boo (Wiwat Pattarachupong – PTTEP International) | Moses, Nicholas (Simon James West – Schlumberger) | Syifaa'i, Arfi (Simon James West – Schlumberger) | Wallace, Cal (Simon James West – Schlumberger) | Ling, Chin Pui (Simon James West – Schlumberger) | Kikuchi, Masato (Simon James West – Schlumberger)
This paper covers the design, execution, and evaluation of the development of the Zawtika field operated by PTTEPI in Myanmar. This includes the study of the reservoir, the selection of completion methodology, the operational challenges, and the performance of the wells.
The Zawtika field development focused on the laminated Plio-Pleistocene reservoirs. The formation comprises a thick sequence of mixed deltaic and shallow marine clastic sediments. A conservative geomechanics study indicated that any reservoirs shallower than 1,700 m true vertical depth (TVD) have high sanding risks and would require an active sand control method.
A batch completion campaign was planned and deployed as a mix of single-zone and stacked dual-zone cased-hole gravel packs (CHGP). A pre-gravel pack acid treatment was tailored for formations with high chlorite content and fines stabilization. A fracture- and gravel-pack service was the primary gravel pack option followed by high-rate water pack (HRWP) depending on water zone proximity or a lack of stress barrier. The sanction that was placed on the country at the startup of this campaign and the limited infrastructure in place led to various challenges during different stages of the campaign.
Over 15 months, 17 wells were completed on three platforms with eight single-zone wells and nine stacked dual-zone wells. This totaled 26 zones where 10 zones were completed with the fracture- and gravel-pack service and 16 zones with HRWP. These jobs were executed on a tender assist for the first platform and on a hydraulic workover unit for the following two platforms. These were among the notable points for the campaign:
First CHGP completion in Myanmar
Achieved production objective with zero sand production
Introduced the technique of pumping HRWP in sweep stages for longer intervals in Myanmar
Introduced several fluid systems in Myanmar, including a polymer-free carrier fluid, acid system with diverting agent, fluid loss pill, and clay stabilizer
Completed all wells without downtime related to delivery of products despite the remote location and logistics between multiple countries
Completed the campaign without any HSE incident and with high operating efficiency
With 17% of the global population, India faces a huge challenge to meet its growing domestic energy consumption, especially as it holds only 0.35% of oil reserves and 0.6% of natural gas reserves in the world.
As a result of dynamic economic growth, the country’s oil consumption is expected to increase from 3.7 million BOPD in 2013 to approximately 4.4 million BOPD by 2018.
According to the BP Statistical Review of World Energy 2014, India’s proved oil reserves stand at 5.7 billion bbl with a production of 894,000 BOPD. Ranked as the fourth largest oil consumer after China, United States, and Russia, the country imports 82% of oil and 25% of natural gas to meet its demand.
Approximately 56% of India’s reserves are offshore and 44% onshore. The majority of the reserves is located in the western offshore region, near Gujarat and Rajasthan. The Assam-Arakan basin in the northeastern region holds 23% of reserves and 12% of the production in the country.
Although the country has enormous production potential, exploration efforts have not yet tapped the Indian sedimentary basin. Data from the Directorate General of Hydrocarbons (DGH) showed that India has a sedimentary area of 3.14 million km2 consisting of 26 basins, of which 1.39 million km2 is onshore, 0.4 million km2 is located in shallow water, and 1.35 million km2 is located in deep water. Deepwater oil production began in September 2008 when Reliance Industries (RIL), India’s largest private sector company, started production in the KG-D6 block of the Krishna-Godavari basin in the eastern offshore region.
According to the state-controlled Oil and Natural Gas Corp. (ONGC), only 22% of the sedimentary area is well explored, 44% has had exploration initiated, 12% is poorly explored, and 22% is unexplored. Of the 26 basins, only seven are currently producing.
To boost investment in the upstream sector, Indian exploration and production (E&P) companies want the government to provide incentives to local players. “The core policy initiative of the government of India’s ‘Make in India’ can gain necessary momentum and direction if supplemented by ‘Discover in India’ initiative, the latter aimed at discovering, developing, and producing energy resources in India,” said Manish Maheshwari, chief executive officer of Essar Oil E&P.
Maheshwari said that policies with a clarity of intent and richness in content are needed to attract the much needed capital in the upstream E&P sector. “We expect the Ministry of Petroleum and Natural Gas to usher in the next wave of reforms in the E&P sector through various policy initiatives. For instance, exploration focus through open acreage licensing policy, execution driven through simultaneous exploration and production of reserves across conventional and unconventional plays, and ensuring fiscal certainty,” he said.