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Rachapudi, R. V. (ADNOC Onshore) | Al-Jaberi, S. S. (ADNOC) | Al Hashemi, M. (ADNOC) | Punnapala, S. (ADNOC Onshore) | Alshehhi, S. S. (ADNOC Onshore) | Talib, N. (ADNOC Onshore) | Loayza, A. F. Jimenez (ADNOC Onshore) | Al Nuimi, S. (ADNOC Onshore) | Elbekshi, A. (ADNOC Onshore) | Quintero, F. (ADNOC Onshore) | Yuliyanto, T. (ADNOC Onshore) | Abd Rashid, A. Bin (ADNOC Onshore) | Alkatheeri, F. Omar (ADNOC Onshore) | Gutierrez, Daniel (ADNOC Onshore) | Chehabi, W. (Fishbone A/S) | Hussain, Ali Ba (ADNOC Onshore)
Productivity enhancement of tight carbonate reservoirs (permeability 1-3 md) is critical to deliver the mandated production and to achieve the overall recovery. However, productivity improvement with conventional acid stimulation is very limited and short-lived. Tight reservoirs development with down spacing and higher number of infill wells can increase the oil recovery. Nevertheless, poor vertical communication (Kv/Kh < 0.5) within the layered reservoir is still a challenge for productivity enhancement and needs to be improved.
First time successful installation of fishbone stimulation technology at ADNOC Onshore targeted establishing vertical communication between layers, in addition to maximizing the reservoir contact. Furthermore this advanced stimulation technology connects the natural fractures within the reservoir, bypasses near well bore damage and allows the thin sub layers to produce. This technology requires running standard lower completion tubing with Fishbone subs preloaded with 40ft needles, and stimulation with rig on site. This paper presents the case study of the fishbone stimulation technology implemented at one of the tight-layered carbonate reservoir.
A new development well from ADNOC Onshore South East field was selected for implementation of this technology. The well completion consisting of 4 ½ liner with 40 fishbone subs was installed, each sub containing four needles at 90 degrees phasing capable of penetrating the reservoir up to 40 ft. While rig on site, acid job was conducted for creating jetting effect to penetrate the needles into the formation. Upon completion of jetting operation, fishbone basket run cleaned the unpenetrated needles present in the liner to establish the accessibility up to the total depth. Overall, application of this technology improved the well production rate to 1600 BOPD compared to 400 BOPD of production from nearby wells in the same PAD and reservoir. In addition the productivity of the candidate well improved by 2.5 times with respect to near-by wells in the same PAD. Currently, long-term sustainability testing preparation is in progress. This paper provides the details of candidate selection, completion design, technology limitations, operational challenges, post job testing and lessons learned during pilot implementation. In summary, successful application of this technology is a game changer for tight carbonate productivity enhancement that improves the overall recovery along with optimizing the drilling requirements. Currently, preparation for implementation of 10 pilots in one of the asset at ADNOC Onshore fields is in progress.
Soni, Kishan (Petroleum Affairs Division, Department of Communications, Climate Action and Environment, Ireland/ iCRAG, School of Earth Sciences, University College Dublin) | Manzocchi, Tom (iCRAG, School of Earth Sciences, University College Dublin) | Haughton, Peter (iCRAG, School of Earth Sciences, University College Dublin) | Carneiro, Marcus (iCRAG, School of Earth Sciences, University College Dublin)
Oil reservoirs hosted in deep-water slope channel deposits are a challenge to manage and model. A six-level hierarchical arrangement of depositional elements within slope channel deposits has been widely recognized, and dimensional (width and thickness) and stacking (amalgamation ratio and volume fraction) data have been acquired from published studies to establish parameters for a representative slope channel system. A new static modelling workflow has been developed for building models of channel complexes based on a simplified hierarchical scheme using industry-standard object-based modelling methods and a new plugin applying the compression algorithm. Object-based modelling using the compression algorithm allows for independent input of volume fractions and amalgamation ratios for channel and sheet objects within a hierarchical modelling workflow. A base-case channel complex model is built at the resolution of individual sandstone beds, conditioned to representative dimensional and stacking characteristics of natural systems. Inclusion of explicit channel axis and margin regions within the channels governs bed placement and controls inter-channel connectivity where channels are amalgamated. The distribution of porosity and permeability within these beds mimics grain-size trends of fining in the vertical and lateral directions. The influence of various geological parameters and modelling choices on reservoir performance have been assessed through water-flood flow simulation modelling. Omission of the compression method in the modelling workflow results in a three-fold increase in oil recovery at water-breakthrough, because the resultant unnaturally high amalgamation ratios result in overly-connected flow units at all hierarchical levels. Omission in the modelling of either the bed-scale hierarchical level, or of the axial and marginal constraints on the bed placement in models that do include this level, results in a two-fold increase in oil recovery at water-breakthrough relative to the base-case, because in these cases the channel-channel connections are too permissive.
Time-lapse (4D) seismic is an essential tool for monitoring the subsurface in and around producing hydrocarbon or CO2 storage reservoirs. The seismic time-shifts, in the reservoir as well as in the overburden, depend on the stress changes and strains induced by the subsurface depletion or the inflation. In this study, geomechanical modeling is used to quantify the stress changes and strains in a synthetic model for the formations in and around a depleting reservoir. The estimated strains are coupled to experimentally determined strain sensitivities for P-wave velocities of shales, to predict time-shifts in the surroundings of the reservoir. The modeling shows that the stiffness contrast between the reservoir and its surroundings plays an important role in controlling the stress and strain changes in the subsurface. The strain sensitivity of the vertical P-wave velocity in the surroundings is significant and is rapidly increasing in magnitude with the proximity to the reservoir. Correspondingly, the time-shifts are increasing with depth in the overburden and decreasing with depth in the underburden. In this study, the time-shifts of the surroundings are changing most between the depths corresponding to one and two reservoir radii above and below the reservoir. Presentation Date: Wednesday, October 14, 2020 Session Start Time: 8:30 AM Presentation Time: 11:00 AM Location: 360A Presentation Type: Oral
In this work the potential for gas production from two selected methane hydrate deposits which are situated offshore from Uruguay is assessed along with the validity of numerical simulations as a tool for analysis in this environment. Gas hydrates are crystalline solids formed by gas and water, in which gas molecules are accommodated within a solid water lattice in a cage-like structure. They form in thermobaric conditions of relatively high pressure and low temperature which in nature occur in permafrost and deep water sediment environments. Marine methane hydrates represent a huge potential as an unconventional gas resource and production tests have already been perfomed offshore Japan and China confirming the validity of depressuration as a method of production.
Available 3D seismic data was utilized for the identification of interesting areas for gas hydrate studies focused on resource exploitation allowing the acquisition of the corresponding architectural parameters. Due to the lack of well data at the selected locations, geological models and reservoir properties were defined based on published data from studies on analogue situations including data from the first production test performed offshore of Japan. Reservoir simulations were carried out to assess the response of selected prospects to depressurization induced dissociation.
Two prospects, interpreted as turbidite type deposits and located at 1850 m and 788 m of water depth, were selected for the modelling studies. The simulation of short term production tests of 60 days indicates average gas release rate values from 34 100 std m3/d to 6700 std m3/d for the deeper and shallower prospect respectively. The simulations were greatly affected by geometrical non-geological parameters like the proximity of model boundaries as well as type and level of discretization. We found that for finer discretization cases, the use of logarithmically distributed radial grid cells led to the existence of artifacts at early time on the gas release rate curves while the use of uniformly distributed radial cells results in more stable behaviour of the gas release rate. Several realizations of the geological models were used and sensitivity analysis was carried out regarding permeability and hydrate saturation. A longer term production regime (10 years) for a heterogeneous layered case was also simulated for the deeper prospect resulting in very useful average gas release rates of approximately 70 000 std m3/d, essential to satisfy gas requirements of Uruguay. We predict that only a few wells would be needed.
For the first time, reservoir simulation was applied for prospects in Uruguay and the gas release potential for marine methane hydrate deposits in the Southern Atlantic margin was assessed. Simulation results are encouraging. Additionally the results of this work at the identified prospects may be useful for site selection for any future campaign for gas hydrate exploration offshore Uruguay.
Li, Hangyu (China University of Petroleum, East China) | Zhang, Ming (Research Institute of Petroleum Exploration and Development, PetroChina) | Lau, Hon (National University of Singapore) | Fu, Shiwen (X'ian Petroleum University)
At present, China has three major deepwater oil and gas fields located in the Qiongdongnan and Pearl River Mouth basins in the South China Sea (SCS) at water depths ranging from 300 m to over 1500 m. In this paper we compare the geology, reservoir and fluid properties and development concepts of these deepwater fields with those in the Gulf of Mexico (GOM), Nigeria and Brazil. Based on this comparison, we have identified several key subsurface challenges and opportunities for future deepwater field developments in the SCS. Major subsurface challenges include smaller in-place volumes, heavier oil, lower reservoir energy and higher reservoir temperature. Opportunities identified include locating continental margin systems with high accommodation volumes and thick sandstone supply, use of alternative development concepts such as Floating Liquified Natural Gas (FLNG) and complaint platforms with dry tree wells and learnings from the recent development of lower-permeability reservoirs in deepwater GOM and the heavy oil deepwater developments and CO 2 handling techniques in Brazil.
Microfiuidics and nanofiuidics have been used in the oil and gas industry for pore-scale research experiments and as application-specific tools (such as lab-on-a-chip PVT analyzers). The former technology constructs pore and pore-network proxies on compact lab-on-a-chip devices. Such proxies are then used to investigate the impact of specifically tuned geometric and/or material variable(s) on fluid transport via direct observation with microscopy. This paper reviews micro/nanofluidics findings by the authors and other geoscience and general porous-media researchers. Findings are related to the impacts of pore size, surface chemistry (wettability), fluid type and composition, and surface texture (roughness) on fluid transport variables, such as effective viscosity, imbibition, capillary trapping, adsorption, and diffusive processes. For example, the authors’ microfluidic findings include a critical surface roughness value beyond which capillary trapping during drainage increases drastically due to changes in subporescale flow regimes. The authors’ nanofluidic findings include that the fluid polarity and surface chemistry of a silica nanoconfinement can lead to additional contactline friction that causes significant deviations from the continuum Washburn equation for imbibition; these effects can potentially be incorporated in the quantitative analysis through an increased effective viscosity. Finally, this review highlights practical approaches for using labon-a-chip devices and their associated pore-scale findings as diagnostic tools to augment petrophysical laboratory measurements and guide field-scale pilot operations.
Abstract Does the sub-surface drive completion design or is the rock less of a concern with industry trends to higher proppant-, fluid- and stage-intensities? To address this challenge it was first necessary to understand; 1) how the sub-surface could potentially influence completion and stimulation design, 2) what are the available engineering levers and moreover, 3) whether well performance has actually been impacted by tailoring completions in different plays from specific case-studies. Although there is a multitude of published field examples of how completion design changes have driven value, clarity around the inter-connectedness with sub-surface variability, either between plays or within a play, is commonly missing. New templates have been developed that describe the conceptual links between the nine key 'Sub-surface Drivers' for hydraulic fracturing and their associated engineering Levers categorized by well-, fluid-, proppant- and stage-design. These templates are a compilation of extensive empirical observations from both operations and field performance reviews incorporating thousands of wells across North America, supported with learnings from geomechanical theory and modeling. The nine Sub-surface Drivers that influence completion design and control the access to hydrocarbons are, 1) mobility, 2) reservoir pressure, 3) gross thickness, 4) layering heterogeneity, 5) rock stiffness, 6) natural fractures, 7) stress anisotropy, 8) risk of fraccing faults and, 9) risk of fraccing out of zone. Drivers 1-7 govern the connectivity, whereas 8 and 9 influence stimulation ineffectiveness. It is proposed that there are approximately fifteen primary engineering Levers related to these nine Drivers, which have been shown to have a measurable impact on completion effectiveness and/or production. Case studies illustrate that the Sub-surface Drivers play a significant role in most plays, but they are not all relevant in every play. The challenge is to acknowledge the variability, or lack of, and pursue completion design optimization goals, while managing the variance in the well performance range. Whereas industry trends of increasing completions intensity have delivered more value in many plays, the Sub-surface Drivers concept have primarily proven useful to mitigate against poor wells in development and explain exploration failures. By developing a systematic set of templates for Drivers and their respective levers, learnings from other operators can be high-graded through the formulation of connectivity analogues with the goal of showing where changes in completion design may be more, or less applicable.
Abstract Many casing failure incidents have been reported in oil and gas fields around the world. These casing failure events can occur not only within reservoirs but also in surrounding formations. Engineers must evaluate risks of casing failure when drilling and completing wells especially in highly compacting reservoirs. However, one of the challenges encountered during the evaluation of casing failure risks is that field-scale stress changes and displacements as a result of drilling wells and producing hydrocarbon from reservoirs must be properly taken into account for casing stability analysis. The objective of this study is to develop an efficient integration method for large-scale reservoir compaction and small-scale casing stability analyses for the evaluation of casing deformation and failure. The numerical model developed in this work is based on 3D elasto-plastic finite element method (FEM). Reservoir compaction and subsidence are analyzed using a large-scale FEM model considering details of geological settings while casing stability is analyzed separately by a small-scale FEM model. The two FEM models are integrated by interpolating displacements calculated by the large-scale model and assigning resultant displacements for boundaries of the small-scale casing stability analysis model. The validation of the proposed integration method is also presented in the paper. Our study results indicate that the integration method presented in this paper significantly improves computational efficiencies on an order of 5 times faster than the conventional simulation method that requires a large number of finite elements for reservoir, surrounding formations, cement, and casing. Also it is demonstrated that the integrated model can be applied to inclined wells completed in highly heterogeneous formations at sufficient accuracy. The field case study also indicates that the risk of casing deformation highly depends on its inclination and the position relative to the compacting formation. The small and large scale coupling method developed in this work helps engineers evaluate casing deformation and failure in various locations in reservoir and surrounding formations in an efficient manner and also develop safe and efficient drilling and completion programs to reduce risk of casing mechanical problems.
Alexeyev, Alan (Department of Petroleum Engineering, University of North Dakota) | Ostadhassan, Mehdi (Department of Petroleum Engineering, University of North Dakota) | Bubach, Bailey (Department of Petroleum Engineering, University of North Dakota) | Boualam, Aldjia (Department of Petroleum Engineering, University of North Dakota) | Djezzar, Sofiane (Department of Petroleum Engineering, University of North Dakota)
The scope of the work is done on a producing oilfield in the North Dakota portion of the basin. Well logs from 45 wells in Blue Buttes Field were analyzed, mainly focusing on the Middle Bakken section of the Bakken Formation. Reservoir properties, such as permeability, effective porosity, shale volume, and saturation were determined using a set of commercial software. Several methods for analyzing each property were tried, the results were compared and the best method was picked that matched the core analysis such as the XRD scanning. The results of this study can help with a decision regarding the further development of the reservoir specifically in the Blue Buttes Field or to improve the understanding of various properties from the Middle Bakken. The procedures presented in this paper will help to establish a workflow for similar studies in other unconventional reservoirs in the future. This case study also helps better understand the lithology and rock properties of the Middle Bakken.