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AL Isaee, Omar (Petroleum Development Oman) | Chavez Florez, Juan (Petroleum Development Oman) | Ali, Nada (Schlumberger) | AL Ghatrifi, Rawan (Petroleum Development Oman) | Al-Yaqoubi, Mazin (Petroleum Development Oman) | AL Abri, Ahmed (Petroleum Development Oman) | AL Hinai, Mohamed (Petroleum Development Oman)
In Oman, the unique geological properties of the reservoirs require different fracture strategies and technology deployment to make them commercially viable. Highly deviated wells, with multiple hydraulic fractures, have been identified as key technology enabler for the development of tight gas accumulations in Oman. The main objective of this study is to generate a 3D petrophysical and geomechanical view of the reservoir, to have a better understating of Hydraulic Fracturing for Horizontal and Highly Deviated Wells
The comprehensive amount of data captured during the initial implementation phase of highly deviated wells covering reservoir characterization, fracture geomechanics as well as production logs in combination with the existent data captured in vertical wells, proves to be complex to analyze due to the volume of information and the multi variable nature associated with fracture and inflow predictions. A methodology was required where correlations and tendencies were identifiable at structural level, covering all target gas accumulations using all the static and dynamic captured data. The definition of a 3D Grid Visualization Block (3D-GVB) was introduced where all the captured parameters were distributed for analysis and interpretation.
As a result of the appraisal and initial field development with vertical wells, it was possible to identify tight accumulations that will require dedicated highly deviated wells for its development. The initial phase of the implementation of highly deviated wells proves to be challenging, as the observed heterogeneities on geomechanical and petrophysical properties across the target gas accumulations, combined with differential depletion and the wells orientation to generate transverse fractures, creates a complex environment for fracture initiation and propagation, impacting not only fracture deployment but inflow deliverability of this wells. This paper will describe how the methodology uses a cycle of data analysis and interpretation to identify tendencies, that will lead to correlation and new algorithms that are retrofitted on the 3D-GVB platform, leading to optimization of well positioning at structural level, drilling and completion of this highly deviated wells.
It will be described how this methodology is used for well positioning at structural level, to define well architectures oriented to enhance not only drilling, but also hydraulic fracturing and hydrocarbon deliverability on highly deviated wells.
The paper discusses a petrophysical evaluation method for complex tight gas formations in a mature and partially depleted gas condensate field in Oman, allowing a full petrophyscial evaluation as well as geomechanical modeling from a source-less petrophysical dataset, thus reducing operational data acquisition risk in partially depleted reservoirs without compromising on hydraulic fracturing design. The developed methodology includes the volume of shale estimation from correlation with Poisson's ratio for the feldspathic rich tight formation.
The subject field (Field NG) is one of the largest matured oil accumulations located in the South of Oman Salt Basin. Production and integrity issues have been the main challenge in recent years, manifesting in abnormal behavior of water-cut with time. Hence, detailed technical multidisciplinary studies were conducted in order to identify causes and propose mitigations.
The base historical performance of the field showed water cut progression behaving as a matrix block, however, in recent years new wells started showing unexpectedly higher initial water production (fracture like behavior). A thorough investigation was carried out utilizing numerical simulation models calibrated to Field NG production history in order to characterize the type of rock behavior (matrix behavior, conductive streaks, fractures, faults, etc). The study concluded that the water cut behavior was due to naturally-occurring fractures which are limited in length and not vertically extensive. During the early stages of production, when the initial water-cut shows matrix like behavior, the bottom water is not in contact with the fracture network. However, after years of production and rise of the water table, the fracture behavior became dominant as the water gets in contact with the small vertical fractures. The presence of these fractures were confirmed by a total of 11 FMI data taken since 2015.
The proposed solutions included detecting fractures early on using bore-hole imaging techniques and utilizing EZIPS in sealing as many fractures as possible. This completion method resulted in delayed water production and increased NPV by 2-3 $MM per well. Moreover, new and efficient WRFM technologies such as Autonomous Inflow Control Devices (AICDs) have been deployed in horizontal wells which selectively limit water flow. Initial results from the early implementations of AICDs are very encouraging.
Thermal recovery is becoming a main stream enhanced recovery method for heavy oil with unique challenges. The extreme nature of thermal recovery requires flexible and creative approach to address the unique challenges. One of the accepted recovery thermal methods is Cyclic Steam Stimulation (CSS). The thermal cycle starts with injection phase followed by soaking, and finally, production phase. Conversion from injection phase to production phase is considered a significant operational risk in addition to typical risks associated with oil production operations. The additional risk during the conversion to production from an injection cycle is due to the significant energy placement in the reservoir during steaming. If not controlled, high energy hydrocarbon fluids flowing back to surface can lead to loss of containment and harm to life or the environment.
Beam Pumps have been used predominantly in conjunction with insert down-hole pump and sucker rods. During injection phase, the well is operated as an injector without pumps or rods, and when the time comes to convert to a producer, rods and insert pumps are reinstalled. This conversion step from injector to producer is highest risk in the CSS well operation cycle.
After the injection cycle is completed, a significant energy is placed into the reservoir, the well is shut in for soaking period which is 1-3 days. Free flow is required after the shut in period to depressurize the well. Depressurization period extends in some cases to many weeks and would require killing the well where it's common that a well would not die off just by depressurization alone resulting in significant wait time. The amount of flow back and energy stored in the well is directly proportional to steam injection pressure and duration.
In many cases where well still retain some energy and pressure is still high for intervention, due to free flowing not subsiding, killing the well is utilized. Well killing procedures pose another set of challenges such as; pump start up challenges due to viscosity reduction, cost for brine mix and wrong pressure estimation leading to prolong interventions.
The challenges in CSS opened an opportunity for innovation where thermal wells could be attended for conversion with minimum rods taken out or rods added back in under high temperature and pressure. The new concept is a combination of dual rod Blow Out Preventer (BOP) and stripper seals set in series. A trial in November 2017 was conducted with positive results where the advantages of this innovation were clearly demonstrated. This paper is a summary of the design approach and the successful trial proving the concept.
Transform has over the last 30years set up several projects for treating oil contaminated water and sludge. Special attention has been to treat and recirculate wastewater from car, container and train wash. With this experience it was decided to test and acquire an EU Environmental Technology Verification. Result of this test is that the specific developed Rootzone soil filter can adapt and decompose oil contaminant. It is documented that the treated water can be recirculated or reused for irrigation or other purposes. Approval from EU was given on the 9 th of January 2018, as the first and only approval by EU of treating oil contamination. This presentation is the first given since approval.
Field K1 as part of AA Tight Gas Cluster features significant variability in the fluid properties, concluded through PVT, well test as well as geochemical measurements. Following an extensive data acquisition program that was conducted at the beginning of the project, a multi-disciplinary review and integration of data was carried out in order to adequately characterize the fluid distribution across the field.
Several analyses were employed to understand the characterization of the fluid distribution through geochemistry analysis, compositional gradient analysis and lateral fluid investigation.
Gas samples and mud gases were collected during drilling and analyzed for gross composition and stable carbon isotope for geochemical analysis purposes. Condensates were collected and analyzed for gross composition, sulfur content and isotopic analyses. Analyses of both fluid types aimed at gathering reliable information in terms of source type and thermal maturity of gases. The large number of data points from high resolution sampling of mud gases allowed for a more confident examination of charge history and communication of the Upper Amin Formation across the cluster of fields.
The gas and condensate samples were taken after well completion for further PVT analysis. Gas composition, temperature, fraction of liquid drop-out and measured Dew Points suggested complex reservoir fluid and genetically different behavior with a contrasted fluid signature across Field K1. Plotting the fluid composition, phase envelopes, as well as Dew Point gradient supported application of a complex-fluid modeling together with segmentation.
The understanding of the fluid behavior is important for the reservoir description as well as the overall development plan of Field K1. The impact on the development plan includes: missing condensate recovery opportunity, on-plot and off-plot facility design, overall gas and condensate recovery factor per well, and the sequence of development.
This new analysis resulted in an upward update in resource volume estimation of Field K1. Well placement and drilling sequence optimization were derived as the positive outcome of this exercise.
Heidorn, Rodrigo (Petroleum Development Oman) | Salem, Hisham (Petroleum Development Oman) | Shuaili, Salim (Petroleum Development Oman) | Khattak, Ali (Petroleum Development Oman) | Pentland, Christopher (Petroleum Development Oman)
The Eastern Flank part of the South Oman Salt Basin of the Sultanate of Oman is an important area for Oman's overall oil production. The fields are largely controlled by deep seated reactivated Neoproterozoic faults and halokinesis of the Infra-Cambrian Ara Group responsible for rich varieties of complex structural styles which have direct impact on field performance and development. The fidelity of newer seismic, the ever increasing information from wells and better integration of various data sets of different disciplines allow new insights into the unlocking of remaining hydrocarbons within existing fields and within near field exploration opportunities.
The South Oman Salt Basin is subdivided into four NE-trending salt-related structural domains based on the type of salt withdrawal minibasins present. The Eastern Flank is located within structural domain I. Domain I represents the area where evaporites have been initially present, but have been subsequently removed by salt-dissolution and salt evacuation. The dominant structure style is the ‘mini turtle back structure', which shows a diverse structural architecture and is systematically classified based on structure- and fault architecture. Domain II is the zone of the large inverted salt withdrawal minibasin or turtle back structure which is located at the salt edge of the basin with evaporite presence in the subsurface. The structural style of a large turtle back structure shows complexities within the core of the structure and within the surrounding rim related to inversion and truncation of the Carboniferous and Permian reservoirs. This is reflected by the various development scenarios related to simple and complex cores as well as to simple and complex rims. Fault compartmentalization has a strong impact on field performance within domain I and II, thus several types of faults are established based on fault architecture and location within the structure. The systematic classification of structural styles and faults allow the establishment of analogues, which are in particular valuable for seismically poorly imaged areas. A new tool captures and centralizes the structural data, as well as a large range of other data sets within the production and geoscience environment from over 60 fields with the aim to make more consistent and better as well as quicker decisions related to field development planning.
Distributed fiber-optic sensing, and specifically the introduction of intelligent distributed acoustic sensing (DAS), has gained the attention of production engineers with the promise of a versatile and cost-effective decision-support tool. These systems can either be permanently installed, or temporarily deployed using diverse types of intervention systems.
This article covers the principles of flow allocation using distributed sensing and show how these can be used and combined to identify fluid-entry points, quantify production and identify fluid phases. We will describe the methods used to improve quantitative interpretation from distributed sensing, especially the use of phase-coherent DAS for quantitative measurement of sound speed and its use in analysis of flow velocity and fluid phase.
While early DAS systems were previously limited in their flow-detection thresholds we have recently introduced a new sensing system, bringing a 20dB (100×) improvement in signal-to-noise. This offers a significant improvement in measurement and associated interpretation capability.
Distributed fiber-optic sensors were invented in the 1980s (Hartog, 1983) and introduced into the oilfield in the 1990s. The initial areas of interest, and commercially available technologies, were related to distributed temperature sensors (DTS) and distributed strain sensors (DSS). DTS was applied to leak detection, flow profiling and steamflood-monitoring applications (Smolen and van der Spek, 2003). DSS focused mainly on wellbore integrity, monitoring strain induced on wellbore casings (Li et a., 2004). Some research has also been carried out on the use of DSS systems for distributed pressure sensing, but to date, these have not delivered the required performance and reliability for commercial application.
This paper reports on the startup of Phase 1 of a Solar Steam Generation facility (SSG) and its export to the existing steam headers of the Amal oil field, located in the south of Oman. Significant considerations within the SSG are reviewed and the impacts on the client's systems identified and discussed. Operational performance indicators on SSG and Client facilities are studied, primarily based on process operating data and equipment stability records, to ensure that the supply of variable steam from solar generation does not create any detrimental effects on the existing facilities. Of particular interest is to assess the success of a variable rate steam injection mode and the impact this has on Client facilities: system pressures, conventional steam generator operation, and wellhead steam injection rates. Previous simulation work has demonstrated that this mode of operation is essentially equivalent to fixed steaming rates provided the same daily equivalent of steam is injected in both cases.
Al Shibli, Abdullah (Petroleum Development Oman L.L.C.) | Al Bahri, Sultan (Petroleum Development Oman L.L.C.) | Al Yazidi, Rashid (Petroleum Development Oman L.L.C.) | D' Amours, Kevin (Petroleum Development Oman L.L.C.) | Belghache, Abdesslam (Petroleum Development Oman L.L.C.) | Al Yahyai, Ahmed (Petroleum Development Oman L.L.C.) | Putra, Pristi H (Petroleum Development Oman L.L.C.) | Duggan, Tim (Petroleum Development Oman L.L.C.) | Saileh, Abdulsalam (Petroleum Development Oman L.L.C.) | Al Busaidi, Faisal (Petroleum Development Oman L.L.C.) | Al Abri, Rahma (Petroleum Development Oman L.L.C.) | Lombardi, Jorge (Petroleum Development Oman L.L.C.)
The A West heavy oil reservoir in the South of Sultanate of Oman is a very attractive target for thermal EOR considering its low primary oil recovery of 20%. The field development plan proposed Vertical Steam Drive as a development concept for Phase 1 that included drilling and operating a total of 80 3.3 Acre inverted 7 spots patterns. Vertical and areal steam conformance has been highlighted as one of the main challenges in one of the most complex and thick heavy oil reservoirs in the world. As a result, the plan has proposed executing and operating a smaller spacing 1.1 acre pattern in parallel with full field development of the 3.3 acre patterns. The main objective of the trial is to run a full lifecycle in situ steam flood in 2-3 years compared to 15 – 20 years at field scale spacing. This will accelerate learning on steam breakthrough management in combination with understanding how to improve vertical and areal sweep conformance.
A fully integrated surveillance plan using advanced technologies including down hole DTS temperature fiber cable, covering the whole wellbore have been installed in all producers. In addition to that real-time wellhead temperature monitoring is a key surveillance element to sense the impact of steam break-through in the producers. Multi-tracers injection will also be executed to monitor the areal sweep efficiency and estimate the preferential movement of the steam within the subsurface by measuring the concentration of the tracer in the producers. Along with that, mechanical conformance applications have been installed in the steam injectors to add an additional control on vertical steam conformance and test the effectiveness of such application on addressing steam break-through issues.
The trial will provide direct experience in managing steam injection and production after steam breakthrough that can later be implemented on a larger scale. The integrated data from the trial will aid in calibrating the simulation models to anticipate the time to steam breakthrough and build confidence in the power of the model for short/long term forecasting. In addition, it will also provide early indications of the effectiveness of some of the new technologies and surveillance in predicting and addressing steam conformance challenges and hence optimize the steam flood process.