Multistage hydraulically fractured horizontal well completions have come a long way in the last two decades. Much of this advancement can be attributed to the shale gas revolution, from which numerous transformational tools, techniques, and concepts have led to the efficient development of ultralow-permeability resources on a massive scale. Part of this achievement has been through a widespread trial and error approach, with the higher risk/failure tolerance that is a trademark of the statistical nature of the North American unconventional resource business. However, careful consideration must be taken not to blindly apply these techniques in more permeable tight gas formations, which often cover an extensive range of permeability. Inappropriate application can compromise the effectiveness of the hydraulic fracture treatment and impair long-term well productivity.
Khazzan is a tight to low-end conventional gas field in the Sultanate of Oman, with low porosity and permeability in comparison to conventional formations. The target formations comprise extremely hard, highly stressed rocks at high temperature. The development strategy included vertical wells with massive hydraulic fracture treatments and multistage fractured horizontal wells. The former has been largely successful in the higher-permeability areas, and the economic transition from vertical to horizontal well development, based on rock quality, is continuously evolving. Compared to the rapid learning curve achieved through the more than 80 vertical wells drilled to date, fewer horizontal wells have been drilled, and, as a result, the understanding is still relatively immature.
The paper outlines the technical and operational journey experienced in horizontal wells, to prepare the wellbore and ensure a suitable frac/well connection for successful fracturing and well testing. The paper will describe how the intervention tools and practices have varied between the Barik and Amin formations; depending upon rock quality, frac treatment type, drive to maximize operational efficiency and availability of local resources. The differential application of these techniques, that result in measurable under-flush versus in contrast to the typical North American unconventional practice of defined but limited overflush (e.g., pump-down plug-and-perf will be described). Justification for these different approaches in two very different formations will be demonstrated, including supporting evidence of their relative value.
The obstacles that have been faced, overcome and are still ongoing with this campaign highlight the importance of several critical factors: including multi-disciplinary integration and planning, wellbore construction impacts, contractor performance and tool reliability. Although practices for shale and very low permeability sands are well documented, this paper provides a suite of case histories and operational results for horizontal well intervention techniques used in high-pressure and high-temperature sandstones that are in the very specialized transition zone between conventional and unconventional.
Monitoring and reevaluation of petrophysical attributes in a mature field under production for many decades is crucial for optimizing production and further development planning. In this case study, a multidisciplinary approach is deployed for formation evaluation and reservoir characterization using logging-while-drilling (LWD) sensors spanning formation volumetrics, fluid analysis, high-resolution image interpretation, and geomechanics to confirm remaining oil saturations and help identify recompletion intervals. LWD technologies were used in four wells in Sahmah field of Oman to provide an integrated petrophysical and geomechanical field study using a bottomhole assembly (BHA) including gamma ray, resistivity, formation bulk density, thermal neutron, acoustic, high-resolution imaging, and formation pressure testing sensors. A deterministic multimineral petrophysical model was used to derive formation volumetrics and fluid analysis. Geomechanical interpretation used high-resolution microresistivity imaging, acoustic slownesses, and formation pressure data to verify principal stress orientations and to quantify pore pressure and horizontal minimum and maximum stress magnitudes. These data were then correlated with historical data to evaluate sweep efficiency and residual fluid saturations. LWD sensors have proven to provide robust geological, petrophysical, and geomechanical data compared to previous traditional wireline data acquisition.
The Cambro-Ordovician succession of Saudi Arabia comprises dominantly siliciclastic sediments deposited in a passive margin intracratonic setting and includes the fluvial to marginal marine Saq Formation (Late Cambrian to early Middle Ordovician), the marine Qasim Formation (late Middle to Late Ordovician) and the glaciogenic Sarah Formation (Hirnantian, latest Ordovician). The Saq Formation is subdivided into the Risha Member (Late Cambrian) and the Sajir Member (Early to Middle Ordovician). Palynological age-control in the Risha Member is provided by a characteristic acritarch assemblage (CB1 Palynozone) which contains well-known Furongian (Late Cambrian) diagnostic taxa (e.g., Trunculumarium revinium, Timofeevia phosphoritica and Ninadiacrodium dumontii), as recorded in one subsurface locality in the Arabian Gulf. This typical assemblage occurs worldwide in Furongianaged strata and not only permits a confident age-attribution, but also indicates an open marine facies within the predominantly fluvial to marginal marine lower Saq Formation. In Oman, the same assemblage occurs in the Al-Bashair Member of the Andam Formation. In the lower part of the Sajir Member, one acritarch assemblage characterized by the presence of Acanthodicaodium angustum and Vulcanisphaera spp., was described from a subsurface section in Eastern Saudi Arabia, indicating an earliest Ordovician (Tremadocian) age. This assemblage forms the O6 Palynozone and suggests correlation with the Mabrouk Member of the Andam Formation in Oman.
Sayapov, Ernest (Petroleum Development Oman) | Nunez, Alvaro Javier (Petroleum Development Oman) | Al Salmi, Masoud (Petroleum Development Oman) | Al Farei, Ibrahim (Petroleum Development Oman) | Gheilani, Hamdan (Petroleum Development Oman) | Benchekor, Ahmed (Petroleum Development Oman) | Al-Shanfari, Abdul Aziz (Petroleum Development Oman)
Multistage frac completion (MFC) has been playing a significant role in modern oilfield industry being one of the key tools making development of low permeable formations economical. Commonly, it is applied in horizontal wells that are drilled to compensate for reduced drainage radius of these wells due to a lack of formation conductivity. This technique is evolving, there are quite a few inventions introduced every year that make MFC easier, more economical and that allow the operators to control and precisely evaluate both the treatment itself and performance of the created fractures. However, due to its nature and initial focus on horizontal wells, it did not become very popular in vertical wells. One of the reasons for it is its limited formation access since the sleeves that are providing the access are short and cannot cover the entire net pay. What historically more common in vertical wells are either conventional "plug and perf" approach or its modifications, whereas intervals are perforated with either coiled tubing and sand-blasting perforation or wireline guns, while isolation of the zones is achieved by setting frac plugs, sand plugs or frac packers depending on pumping conduits. In Petroleum Development Oman, some of these vertical wells were stimulated via multistage frac completion.
In central part of the Sultanate of Oman, a deep tight gas field is developed using hydraulic fracture stimulation technique since the formation conductivity is low and the near wellbore damage after drilling is making it even worse. Normally, between 6 and 13 frac intervals are stimulated in each well. Majority of wells are completed vertically with pay zones separated with strong shale layers that restrict fracture height development. Since plug & perf has been the main technique used in this field, there are multiple well interventions during hydraulic fracture operations that consume time, money and delay the well delivery. Moreover, the depletion of the field and its main productive zones make well intervention activities much more challenging whereas the risks of getting coiled tubing string or even wireline tools stuck in wellbore are high due to immediate losses faced after opening those low pressurized zones having as low as 8,000 KPa formation pressure, which can be 5-7 times less than hydrostatic pressures in the wellbore depending on depths and fluid s used. At the same time, with downhole temperatures ranging from 135 to 150 deg C and fracturing pressures reaching around 145,000 KPa bottomhole (~21,000 psi), differential pressures across the target zones can reach enormous levels of 15,000-20,000psi. Conditions in general become very risky, making it extremely difficult to source the right tools and equipment from what is available on the market. Another challenge associated with depletion of this field is an effective deliquification of the wells after stimulation treatments to allow them to effectively get rid of frac fluids and be able to produce gas to surface.
By deploying multistage frac completion with the objective of producing, enhancing and cost/time savings, the effectiveness of the fracturing operations was expected to increase. Multistage frac completion allows the frac operation to be continuously performed without the need to conduct well interventions such as running/setting frac plugs, perforating, milling and clean out between intervals. If needed so, the intervention activities can be completed after frac operations. Equipment selection and completion design were performed based on well conditions, market availabilities, operational parameters and composition of the produced gas. However, this technique is associated with its specific challenges that require attention and tailored solutions. The main challenge in deployment of this system in vertical wells is the accurate positioning of the sleeves. The shale layers between the pay zones could be as narrow as 5 m or less and a small pay zone can be easily missed. Besides, deployment and cementing operations are equally essential because of water zones embedded in between the pays.
This paper is discussing the recognized benefits and lessons learned from utilization of multistage frac completion in vertical deep (around 5000 m) depleted tight gas wells covering the completion and hydraulic fracturing stimulation operations. This technique has industry proven cost & time reduction and efficiency gain, as well as faster well cleanup and reduced HSE exposure contributing to better gas recovery, improvement in operator's performance and energy delivery to the country; it was expected to demonstrate a step change in the efficiency compared to conventional approach to the field development.
Polymer flooding has been identified as the next phase of developing two heavy oil fields located in the South of the Sultanate of Oman. The fields are supported with a strong bottom aquifer drive that results in large amount of water production due to the adverse mobility. In order to prove the concept of polymer sweep, a field trial was designed and conducted successfully in the field. Moreover, due to the challenges associated to handling back produced polymer number of tests were conducted to assess the impact of polymer on facilitates. Development of the field will take place in a phased manner in order to reduce the capex exposure, maximize the utilization of the existing facility and managing project risks while contributing to the overall production.
Dynamic modeling of both fields showed that polymer development is feasible. The modeling work was supported by a field trial that was designed to prove: polymer sweep performance, injectivity, as well as polymer losses to the strong water aquifer. This trial was monitored with detailed surveillance program including pressure, injection/production rates, viscosity and water quality, which concluded incremental oil gain from the process. In parallel, a number of laboratory and field tests were performed to assess the impact of polymer on the surface facilities such as the heater, separation tanks and the growth of the reed beds - wet planets- in the field.
Sustained incremental oil gain was clearly observed from polymer injection in the field trial. Injectivity could not be maintained as planned, due to a combination of polymer, biological and water quality issues. Later tests including biocide injection and QA/QC of polymer batches as well as some well stimulation did show improved injectivity profiles. Demulsifier tests mitigated the risk of creating stable emulsions. Laboratory tests indicated no heater fouling observed below 150°C. Short and long term investigation into the impact of water- contaminated polymer on plants in the wet lands was positive with the plants showing no necrosis. This was tested up to back produce polymer concentration levels of 500 ppm. Which is achievable given the excessive amount of water received at the facility allowing the dilution of back produced polymer to the required level. This helped in making the project more economically attractive as it results in a saving of around 30% from the overall project Capex.
The modeling exercise proposed drilling of around 200 polymer injectors across both fields, but in order to manage costs and further reduce project risks an optimised phased development approach was evaluated. Both Analytical and modeling approach were used to identify the phasing strategy. The phasing strategy will start with the most attractive to least attractive areas allowing for appraisal these areas prior to committing to their development. The key enabler for phasing of this development is by standardizing and replicating the development. Hence, modular facility for polymer preparation and injection was selected, in which a detailed design will be conducted for the first phase then it will be replicated for the other upcoming phases.
Phase-1 of the development will be in the central area as it is has a better response from the model compared to the other areas. This phase will include the drilling of 25 injectors and it will require two modular facilities. 25 to 30 injectors will subsequently be drilled every 2 years for the follow up phases.
The different surface and subsurface tests paved the way for a full field implementation of polymer injection in structures with strong bottom water aquifer. The paper discusses the phasing and replication strategy to mitigate project risks, learn on the go and improve the project’s schedules and economics.
Water flooding has been widely used as secondary oil recovery method in the clastic reservoirs in PDO. Field development plan of this field requires water injection under matrix injection conditions. The field consists of stacked Gharif sand stone reservoirs with variable degree of depletion. Increased injection volumes at economical rate, could induce hydraulic fracturing where it is very important to manage fracture growth and reducing risk for out of zone injection. The success of water flood development depends on an optimal injection pressure, which requires knowledge of formation fracture pressures and geomechanical rock properties.
Efficient geomechanical analysis and workflow integrating data from well tests, field performance, water injection history and monitoring data was implemented for this study to provide guidance on optimum water injection pressure. Field stress tests, such as Leak off Tests (LOT) and micro fracs were analyzed to derive the fracture pressures. Gharif formation in these stacked reservoir formations have been significantly depleted hence a reduction in fracture pressure was required to be assessed. Depletion stress path coefficient, which is the ratio of change of fracture pressure and reservoir depletion, was derived based on historic field data. Data from well tests, field water injection performance was used for Modified Hall plot analysis and other diagnostic plots to provide better insight on active water injection operating conditions (fracture, matrix and plugging). Finally, for injector operating above the fracture pressure, Produced Water Re-Injection (PWRI) model was used to simulate expected fracture dimensions, and quantify the out of zone injection risk.
Results of this study indicate that the decrease in fracture pressure in Gharif formations is about 60% of the change in pore pressure (depletion). Qualitative and quantitative analyses were able to characterize the operating injection conditions (matrix vs. fractured) for active injectors. Interpreted fracture pressure from Gharif water injector diagnostic plots demonstrates good alignment with the measured fracture pressure from field tests. The results reveal that most of the water injector wells, particularly in the depleted formations are operating above fracturing pressure. Predicted fracture dimensions form the PWRI model calibrates well with the field monitoring data.
Outcome of this study provided fracture pressure estimate for Gharif formation with depletion and provide guidance on optimum water injection pressure to improve waterflood management. Stress path chart provide continuous improvement and quick decision for water flood operation. Results quantified the induced fracturing to mitigate the risk of out of zone injection and/or loss of sweep efficiency.
Additionally, the results provide continuous critical input for fracture gradient for drilling and cement design for wells through depleted stacked reservoirs in other field within Gharif formation.
This paper will describe a methodology which has been developed as an alternative to four-dimensional (4D) Seismic. The main objective is to track heat conformance over time in the thermally developed "A" Field, Sultanate of Oman. The method has several significant advantages over 4D Seismic, including: Negligible cost and manpower requirements; Provision of close to real-time information and no processing time requirements; No Health, Safety or Environmental exposure, or disruption to ongoing operations.
Negligible cost and manpower requirements;
Provision of close to real-time information and no processing time requirements;
No Health, Safety or Environmental exposure, or disruption to ongoing operations.
The paper will also demonstrate the power of integrating wide-ranging data sources for effective well and reservoir management.
The increasingly close well spacing at "A" Field has made Seismic Acquisition progressively more challenging. Conversely, it has created an opportunity to utilize dynamic Tubing-Head Temperatures (THTs) for tracking areal thermal conformance over time. For each month in turn an automated workflow:- Grids the monthly THT averages; Integrates the production and injection data, represented as bubble plot overlays; Adds the top reservoir structure from the subsurface model, highlighting structural dip, and fault locations.
Grids the monthly THT averages;
Integrates the production and injection data, represented as bubble plot overlays;
Adds the top reservoir structure from the subsurface model, highlighting structural dip, and fault locations.
Morphing (movie) software then interpolates the monthly images to create a smoothly transitioning "Heat Movie".
The Heat Movie demonstrates the general effectiveness of the Development in terms of warming the reservoir over time. This in turn is reducing the oil viscosity and increasing production. However, it also highlights temperature anomalies that can be linked to geological features such as faults and high permeability layers. Identification of these anomalies may underpin decisions to optimise the thermal development.
In addition to the Movie, time-lapse images can be created for any chosen period. This is similar to 4D Seismic, but more powerful, since the period can be directly linked to significant field milestones, for example equal time periods before and after upgrading the steam generation process.
Proof of Concept was demonstrated in early 2018, and the technique has already been deemed sufficiently mature to utilize it for tracking and managing Thermal Conformance in place of 4D Seismic. This is resulting in annual cost savings of millions of dollars and man-years of staff time.
One potential advantage of 4D Seismic is highlighting vertical conformance. Although this is not possible using THTs alone, at "A" Field the plan is to mitigate this by integrating data from ongoing Distributed Temperature Sensing (DTS) and well temperature surveys.
Regarding applicability, the workflow can be adapted for other objectives, for example creating a movie of surface uplift and/or subsidence integrated with bubble plots of production and injection data, or water breakthrough for wells with downhole gauges, in water flood developments.
In addition to describing the methodology underpinning this innovative approach, this paper will also discuss the vision for further improving the workflow and expanding the functionality.
The Sultanate of Oman, a hidden jewel at the tip of the Arabian Peninsula, ranked fourth safest country in the world for visitors in 2017 by the World Economic Forum. A big part of the Sultanate’s unique charm is the hospitality of the Omani people. There is a big chance that visitors are invited for Omani coffee and dates by locals when travelling through the country, an offer that should never be refused. Even when summer temperatures soar in the rest of the region, the Sultanate enjoys cooler temperatures in Dhofar and the mountain tops of the Al Hajar range, making it a one-of-a-kind holiday destination for visitors from around the world. Oman is a wonderful combination of ageless heritage and modern life.
Committee Chair: Mark Brinsden About the Committee The Energy Information Committee guides and promotes SPE's global programs to inform students and the public of the petroleum industry's value. Although this is primarily an advisory committee that receives substantial staff support from SPE, committee members do provide an important source of hands-on help, access to resources and Energy4me champions. The committee is divided into two subcommittees one focused on classroom education and the other on public awareness. This past year, the committee has focused on encouraging sections and chapters to conduct Energy4me presentations in their communities. Committee Activities and Accomplishments (October 2017 to September 2018) The committee supports globally the growth of SPE's energy education program, Energy4me. They used our hands-on activities to great success UNI Student Chapter: visited two schools Texas A&M Student Chapter: conducted a career day program using Energy4me hands-on activities to illustrate technical concepts UTM Student Chapter: did a school visit, using five Energy4me hands-on activities MIT Pune Student Chapter: multiple workshops over 30 days; reached over 450 students Alexandria Student Chapter: conducted three-month campaign in schools with part of their program consisting of the Energy4me hands-on activities Energy4me staff conducted workshops in six countries, including a first-ever event in Oman. Abu Dhabi, UAE: student workshop, HSSE conference, May 2018 Dhahran, Saudi Arabia: student workshop, ATS&E conference, April 2018 Muscat, Oman: student workshop, OGWA conference, March 2018 Kuala Lumpur: student workshop, OTC Asia conference, March 2018 Mumbai, India: student workshop, OGIC conference, April 2017 Kuwait City, Kuwait: student and teacher workshop, KOGS conference, February 2018 For the first time, Energy4me conducted two student workshops at the training facilities of two international service companies. Both events included touring the sites and interacting with simulators. Baker Hughes Eastern Hemisphere Training Center Weatherford Training and Technology Center 4 P a g e Finally, to provide members with the tools and information they need to conduct a classroom visit, the Energy4me team created a comprehensive, multi-platform training program: Step-by-step video showing the presentation outline Word document that details hands-on activities and required materials for each grade level.
Maxime, France Geosteering Technologies - 9-14 September Downhole Water Management - 16-21 September Wells - How Smart Can They Get? - 23-28 September Asia Pacific Nusa Dua, Indonesia The Application of Seismic Attribute Analysis and Geostatistics in Reservoir Prediction - 13-18 May Optimising Well Productivity with Modern Completion and Stimulation Practices - 20-25 May South America and Caribbean Margarita Island, Venezuela Underbalanced Operations vs Designer Fluids - 28 October-2 November Middle East Muscat, Oman Produced Water Management - The New Reality - 3-8 November 2002 North America Park City, Utah, USA Enhancing Recovery from Deepwater Reservoirs - 7-12 July The Offshore Facility of the Future - 7-12 July E-Well and Wellbore Robotics - 14-19 July Decision-Driven Asset Development and Management - 14-19 July Europe Ste. Saint Maxime, France Smart Drillling - 5-10 September Sand Control and Management - 12-17 September Tight Gas Development - 19-24 September Middle East Muscat, Oman Smart Wells: How Smart Can They Get? - 10-15 January Mature Reservoirs: The Appropiate Application of Technology - 17-22 January P a g e 13 17 Middle East Hammamet, Tunisia The Heavy Oil Challenge: Completion Design and Production Management - 17-22 May 2010 North America Park City, Utah, USA Meet me at the Wellhead - Enhancing the Value Chain in Offshore Installations - 20-25 June - Cancelled Getting to Zero-An incident Free Workplace: How do we get there? P a g e 14 17 Europe The Algarve, Portugal Unlocking the Potential of Nanotech for Exploration and Production - 25-30 September Shale Gas: Beyond Current Technologies and Going Global - 2-7 October CO2 Geological Storage: Will we be ready in time? Can supply expand to keep up with demand exceeding projections? P a g e 15 17 Europe Adaptive Well Construction - 13-18 October Managed Pressure Drilling - Niche Technology or the Future of Drilling?