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. This methodology was used in deep tight fields in Oman for more than 3 years in both vertical and highly deviated wells greatly reducing the risk, logging cost and complexity of operations.
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.
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.
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.
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 9th of January 2018, as the first and only approval by EU of treating oil contamination. This presentation is the first given since approval.
Ge, Q. (Abu Dhabi Company for Onshore Petroleum Operation) | Shahat, A. E. (Abu Dhabi Company for Onshore Petroleum Operation) | Kodiah, B. N. (Abu Dhabi Company for Onshore Petroleum Operation) | Hay, M. A. (Abu Dhabi Company for Onshore Petroleum Operation) | Al-Hosani, M. S. (Abu Dhabi Company for Onshore Petroleum Operation)
Underbalanced Drilling (UBD) has become a popular technique in oil & gas industry, especially for well-developed hydrocarbon fields to minimize formation damage and maximize productivity. The key in UBD is to control bottom hole circulating pressure (BHCP). To maintain BHCP lower than the formation pressure, a light weight drilling fluid has to be used and probably with concurrent N2 injection. In the case of a tight reservoir, N2 injection rate is increased as high as 1500 SCFM, which will cause severe gas slugging and dramatic standpipe pressure (SPP) reduction when the gas is circulated though the choke. MWD signal will then be lost due to the pressure fluctuation. This paper will present a BHA optimization solution to maintain sufficient and stable SPP during UBD.
Two UBD cases will be discussed. Two main challenges were encountered in the first well: one was to reduce BHCP sufficiently low, the other was to maintain SPP high and stable. To reduce the BHCP, MWD pulser was changed from 180-280 GPM rating to 150-250 GPM to allow lower drilling fluid flow rate and increased N2 injection rate to 1500 SCFM. However, surface SPP dropped significantly due to gas slugging. To avoid this happen, the following optimizations were implemented in the second well: 1) added more HWDPs to reduce internal diameter of the drill string; 2) reduced bit TFA by using less nozzles; 3) installed flow rate restrictor in the drill string.
With reduced flow rate and increased N2 injection rate, BHCP was reduced to 300 psi below formation pressure. At the same time, with the optimized BHA, surface SPP was increased sufficiently to transfer MWD signal continuously. According to the simulation, among the 600 psi increase in surface pressure, 300 psi was from the restrictor, 150 psi was from the change of bit nozzles and 150 psi was from the added HWDPs. The main contribution was from the restrictor. Compared with the first well, which was drilled without restrictor, the data retrieved from the second well was smoother and more readable.
It was the first time that downhole flow restrictor was used in UBD well to maintain SPP. Combined with adding HWDPs and reducing bit TFA, SPP was increased sufficiently, whereby enabled continuous signal transmission and better data quality. Therefore, it is recommended to use this technique in the next UBD campaign.
This paper describes an efficient assisted history-matching (AHM) workflow that integrates production logging tool (PLT) data, streamline trajectories, and tracer data for fields with high-permeability streaks (thief zones). A field case study from North Kuwait of Sabriyah Mauddud (SAMA), a giant carbonate reservoir with more than 400 producers, is presented to demonstrate the application of the new AHM algorithm. In this field, the presence of thief zones was identified during a waterflooding period when water breakthrough occurred much earlier than expected. Data from the PLT and limited core plugs also supported the presence of thief zones in several layers of the reservoir and confirmed the majority of the water was flowing through these thief zones. Therefore, PLT data-derived thief-zone logs were used to populate the distribution of thief zones in the geomodel. However, reservoir simulation demonstrated that cumulative water production was significantly lower than the observed value. Streamline trajectories demonstrated that water was flowing homogeneously in the reservoir. Therefore, a new history-matching algorithm that integrated PLT data directly into the workflow and modified the thief-zone distribution was proposed.
The workflow basically identifies the presence of thief zones at the well locations based on PLT data. Streamline trajectories from simulation and available tracer data were used to better understand the connectivity from water injectors to various producers. This information was then used to modify the reservoir model by altering thief-zone distribution. Multiple models were generated by varying the permeability distribution within the generated thief zones and the thickness of the thief zones. These new permeability models were able to produce water at the field level. First, field-level pressure and production rates were matched by adjusting reservoir properties, such as pore volume, oil API, and fault transmissibility. A Markov-Chain Monte-Carlo (MCMC)-based algorithm was used to match well-by-well production rates for oil, water, and bottomhole pressure (BHP). Two-dimensional (2D) discrete cosine transformation (DCT) was applied to the permeability layers to the DCT coefficient domain for optimization purposes. Only low-frequency DCT coefficients that corresponded to thief zones were efficiently sampled during MCMC-based optimization to converge toward an accurate distribution of thief-zone permeability to history match the production data. Therefore, a reduction in sampling space along with the improvement of connectivity helped accelerate convergence. Given the model size and complexity, the optimization converges fairly quickly. Most of the wells demonstrated an excellent match between simulation results and production data of oil, water, and BHP of more than 200 wells with significant production history. PLT data were also closely matched with the simulation production profile at the wellbore. Streamlines of water for the history-matched model demonstrated the water had been flowing through the thief zones. The history-matched model can be further used for better reservoir management and waterflood optimization to improve oil recovery.
A large, strategically important tight gas project in the Sultanate of Oman progressed over 5 years on an accelerated path from exploration to the development stage. Collaboration between operator and service provider helped advance the deployment of technology that made this acceleration possible. Poor initial success in both hydraulic fracturing treatment placement and hydrocarbon productivity along with limited resources with ever-expanding work scope were the main challenges faced in the first 2 years of exploration. To address these challenges, an integrated approach to the project was taken. Technology trials and the selective deployment of technology along with improved operations gave flexibility to this new efficiency model. Close collaboration with the service provider allowed smoother and faster progress. Collaboration included joint technology mapping exercises, team visits to North American locations of the operator and the service provider with the goal of knowledge sharing, faster technology transfer, and the secondment of a senior engineer from the service provider as a full-time production technologist to the operators' subsurface team. The effective execution of strategy and implementation of various technologies resulted in an increase in the success rate of fracture placement and zonal evaluation from the initially low 50% to 100%. The integration of several disciplines was critical to achieving this goal. Technologies deployed in the project comprised of rock and core mechanical tests, such as reservoir coring, openhole stress testing, sonic measurements, continuous unconfined compressive strength measurements, abrasive perforating, various fracturing treatment designs, and several geomechanical studies targeting different aspects of fracture initiation. An additional focus was on the assessment of fracture geometry using radioactive tracers, advanced sonic logging, geomechanical evaluation coupled with geological mapping, microseismic monitoring, and cutting-edge fracture design methodology in both vertical and horizontal wells. The collaborative efforts led to evaluation of similarities and differences between North American and international unconventional projects and suggested techniques and best practices that can be applied in the tight gas project in the Sultanate of Oman. This project has been deemed one of the first commercially successful gas deliveries in the Middle East from a tight gas reservoir. Technologies, methods, and strategies developed for this large tight gas project and tested in the field will contribute to improving the success rate on similar projects around the world.
Large carbonate or anhydrite inclusions are embedded in many salt bodies (so-called rafts, floaters or stringers) and these respond to the movements of the salt in a variety of ways, including displacement, folding and fracturing. The movement and deformation of those embedded carbonate or anhydrite bodies is a process which is not fully understand yet. We presented numerical models of the deformation of salt body with embedded stringers using a case study from the South Oman Salt Basin. We investigated by Abaqus package (finite element models) how differential displacement of the top salt surface induces salt flow and the associated deformation of brittle stringers (including both brittle and viscous material properties) in a compressive environment. The simplified model offers a practical method to investigate complex stringer motion and deformation. Models suggest that brittle stringers can break very soon after the onset of salt tectonics. The compression can make brittle stringer bending and thrusting. Models suggest that viscous stringers have folding and extension deformation. Results also show the internal structure of salt body and stringer fracturing or deformation is strongly dominated by the geometry or material properties of models.
Large rock inclusions are embedded in many salt bodies and these inclusions have different ways of deformation and displacement. The process of salt tectonics has a strong impact on the deformations of the inclusions and there are different typical deformation styles such as displacement, folding, fracture and thrusting. It is of great importance to understand the deformation and displacement of inclusions because of some critical reasons (Li et al., 2012). In the past 30 years, a large number of numerical studies about the deformation of salt structures have been performed (Woidt and Neugebauer, 1980; Last, 1988; Schultz-Ela et al., 1993; Podladchikov, 1993; Poliakov et al., 1993; Van Keken et al., 1993; Daudré and Cloetingh, 1994; Koyi, 1996; Koyi, 1998; Kaus and Podladchikov, 2001; Ismail-Zadeh et al., 2001; Schultz-Ela and Walsh, 2002; Gemmer et al., 2004; Ings and Beaumont, 2010; Fuchs et al., 2011; Abe and Urai, 2012). A few numerical studies have been done regarding the deformation and displacement of inclusions embedded in salt as relatively homogeneous material. Koyi, (2001) and Chemia et al. (2008, 2009) modeled the whole range of the process. Koyi (2001) used physical models and Chemia et al. (2008, 2009) used numerical models to study the whole process of entrainment of anhydrite blocks by a salt structure and their later descent within the structure. Koyi (2001) also used numerical models to quantify the descent rate of entrained anhydrite blocks within a salt diapir. Chemia et al. (2008), Chemia and Koyi (2008) and Chemia et al. (2009) systematically studied the effects of viscosity (Newtonian and non-linear), position of the anhydrite layer, and different rising rate of salt diapirs in connection to entrainment and descent of anhydrite layers/blocks within a salt structure. Burchardt et al. (2011; 2012a, b) used extensive numerical modeling to study the influence of size/aspect ratio and orientation of the denser blocks on the sinking rate and mode.
Oil production in presence of a bottom aquifer is one of the most challenging issues in reservoir engineering. In most cases water coning happens very quickly and the influx of water restricts oil production and limits recovery. The problem is even more difficult when the oil is heavy because the viscosity contrast is large. In some cases horizontal wells may be used to improve the situation but when reservoirs are thin and the oil is viscous even horizontal wells are of limited use. This paper presents the challenges and potential solutions for Enhanced Oil Recovery in heavy oil reservoirs with bottom aquifer. Existing literature is reviewed for field cases of EOR experience with bottom aquifer for chemical as well as thermal processes (SAGD, steam injection as well as In Situ Combustion). In the case of chemical EOR the chemicals may be lost to the aquifer; for thermal recovery the bottom water can act as a heat sink and affect and steam oil ratio. Some in-situ combustion projects have been successful in such settings but in every case the outcome is the same: the economics of the project can be affected. The paper contains some previously unpublished data of polymer injection in a heavy oil pool with some limited bottom aquifer; for the most part it is a review of the existing literature which may prove useful to practicing engineers who are faced with the issue of developing heavy oil resources in the presence of bottom aquifer.