Exploration in the Middle East can benefit from the creation of sequence stratigraphy-based, scalable, 3D models of the subsurface that are, in effect, a subsurface digital twin that extends from the plate to pore. Stratigraphic and structural organization are integrated into this model to provide a predictive geological framework for analysis of reservoir- and regional-scale geology. This framework enables testing of novel geologic concepts on the Arabian Plate.
The first step of model design is to temporally constrain data within a sequence stratigraphic framework. Publically available data were used in the entire construction of this model. This framework enables the generation of plate-wide chronostratigraphic charts and gross depositional environment (GDE) maps that help to define major changes in the regional geological context. The integration of a geodynamic plate model also provides deeper insight into these spatial and temporal changes in geology. The subsurface model also adopts the principles of Earth systems science to provide insight into the nature of paleoclimate and its potential effect on enhancing the predictive capabilities of the subsurface model. A set of plate-scale regional depth frameworks can be constructed. These, when integrated with GDE maps and other stratigraphic data, facilitate basin screening and play risking.
This plate to play methodology has yielded value through the development of new play concepts and ideas across the Arabian Plate. Exploration has historically relied on the identification of large structures. However, the majority of these are now being exploited. Underexplored stratigraphic traps, and unconventional resources are new concepts that can be better evaluated by using a digital twin of the subsurface. The integration of seismic data and sequence-stratigraphy-calibrated wireline log data can be used to identify the subcrop pattern beneath an unconformity, as well as regions where potential reservoir rocks are in juxtaposition with seals. Intrashelf basins are a key feature of the Arabian Plate. They lead to stratigraphic complexity, yet are key factors for both source rock and reservoir development. From an unconventional perspective, novel, tight plays that exist within or above prominent source rock intervals can also be established.
Value and insight into previously underexplored play concepts, such as within the Silurian Qusaiba Member and the Cretaceous Shilaif Formation of Abu Dhabi, can thus be generated from the stratigraphic attribution of geoscience data. This data can enable better-informed predictions into "white space" away from data control.
Al Hosani, Mariam Ahmed (ADNOC Onshore) | Masoud, Rashad Mohamed (ADNOC Onshore) | Al Beshr, Huda Abdullatif (ADNOC Onshore) | Latif, Mohd Anwar (ADNOC Onshore) | Al Hammadi, Shamma Jasem (ADNOC Onshore) | Khalil, Ihab Nabil (ADNOC Onshore) | Al Bairaq, Ahmed Mohamed (ADNOC Onshore) | Al-Ameri, Ammar Faqqas (ADNOC Onshore) | Nasreldin, Gaisoni (Schlumberger) | Ni, Qinglai (Schlumberger) | Rodriguez-Herrera, Adrian (Schlumberger) | El Mubasher, Husham Kamal El Din (Schlumberger) | Corona, Mauricio (Schlumberger) | Sinha, Ravi Kumar (Schlumberger) | Subbiah, Surej Kumar (Schlumberger) | Hussein, Assef Mohamad (Schlumberger) | Karamalla, Babikir Mubarak (Schlumberger)
The growing appreciation of the effects of production-induced stress changes on reservoir performance has concentrated the minds of many people on the potential value of using geomechanical modelling to predict and quantify these effects for making life-of-reservoir decisions—relating to compaction mitigation and completing new wells.
This paper is concerned with well integrity analyses for compacting reservoirs—focusing specifically on a new area of predictive geomechanical modelling realised using the finite element method. The innovative workflow presented offers significant improvements and, for the first time, captures some of the realities of the construction process. It takes into consideration both the formation and completions by integrating 3D near-wellbore geomechanical modelling with cementing simulations and casing integrity analyses. Specifically, casing eccentricity and cement contamination data are taken from numerical cementing simulations carried out to re-create the conditions in wells with different trajectories. Moreover, formation mechanical properties, pore pressure and stress states from the time of drilling till the end of a simulated production schedule are taken from a calibrated field-scale geomechanical model and subsequently used to create high-resolution 3D near-wellbore geomechanical models.
The case study presented in this paper concerns a giant onshore field with multiple stacked reservoirs—containing a variety of hydrocarbons and experiencing different levels of depletion. The main interest is in conducting comprehensive casing and cement integrity assessments—particularly for wells located in compacting reservoir zones. A persistent challenge for geomechanical modelling and prediction is the availability of calibration data. This paper reduces uncertainty by presenting results concerning sensitivity analyses for a variety of completion conditions—including different levels of casing eccentricity, different degrees of cement contamination and different extents of casing corrosion.
One of the considerations in Out-Of-Sequence Fracturing treatment is maximizing reservoir contact by creating fracture complexity through reducing or possibly eliminating or neutralizing the in-situ stress anisotropy (differential stress) to enhance hydraulic fracture conductivity and connectivity by activating planes of weakness (natural fractures, fissures, faults, cleats, etc.) within the formation in order to create secondary or branch fractures (induced stress-relief fractures) and connect them to the main bi-wing hydraulic fractures. In Out-Of-Sequence Fracturing, this is achieved by beginning fracturing Stage 1 at the toe of the well and then moving toward the heel and fracturing Stage 3 so that there is a degree of interference between the two fractures followed by placing Stage 2 between the previously fractured Stages 1 and 3. Out-Of-Sequence Fracturing in this mode ensures that fracture in Stage 2 (Centre Frac) takes advantage of the altered stress in the rock and connects to the stress-relief fractures from the previous Stages 1 and 3 (Outside Fracs), thus enhancing the connectivity and conductivity of the fracture network. Out-Of-Sequence Fracturing has already been tested successfully by LUKOIL Group in treating eight wells in Western Siberia in 2014. The first case of Out-Of-Sequence Fracturing in North America was later conducted in Western Canada in 2017. In this work, a three-dimensional hydraulic fracture extension simulator is rigorously calibrated by history-matching the observed treatment pressures and instantaneous shut-in pressures (ISIP) from the Out-Of-Sequence Fracturing field treatment in Western Canada in order to reliably quantify effective fracture geometries. Then, a separate set of fracture modeling is conducted to predict hydraulic fracture geometries in a conventional (Sequential Fracturing) treatment of the same candidate well. Finally, production forecasting is used to assess the production potential from the candidate well based on each set of the generated fracture geometries from each of the scenarios (Out-Of-Sequence Fracturing versus conventional Sequential Fracturing). The results of coupling rigorously calibrated fracture modeling and production forecasting indicate noticeable production uplift potential from the carefully designed Out-Of-Sequence Fracturing, with the realization that its success is sensitive to both treatment variables (stage spacing, well placement, treatment fluid viscosity and rate, and Centre Frac proppant size and tonnage) and formation's petrophysical and geomechanical properties (magnitude of stress anisotropy, Young's modulus, Poisson's ratio, process zone stress/net extension pressure, fracturing gradient, and matrix permeability).
Kholy, S. M. (Advantek Waste Management Services LLC) | Ma, J. (Heriot-Watt University) | Mohamed, I. M. (Advantek Waste Management Services LLC) | Abou-Sayed, O. (Advantek Waste Management Services LLC) | Abou-Sayed, A. (Advantek Waste Management Services LLC)
Hydraulic fracturing is applied ubiquitously in unconventional hydrocarbon reservoir development to increase the well productivity. To design a frac job, an injection falloff diagnostic test, such as minifrac test, is conducted first to determine key formation properties and frac operational parameters, including fracture closure pressure. In low permeability formations, the conventional pressure falloff analysis (i.e. G-function) is not practical to identify the fracture closure since it requires several days of well shut-in to collect enough pressure falloff data to reveal the fracture closure. In SPE-187495-PA, the authors show that it is possible to develop an empirical equation to predict the fracture closure pressure (Pc) from instantaneous shut-in pressure (ISIP), the first falloff data point, by regressive analysis on datasets from minifrac tests for conventional formations, including G-function estimated Pc, ISIP, petrophysical and mechanical properties. Since petrophysical and mechanical properties could be estimated from cores and wireline logs, the application of this equation requires a minifrac test to have a very short falloff period only to estimate ISIP. The objective of this work is to extend that equation for unconventional formations by introducing appropriate deviation terms for tight-sand and shale formations, respectively, in order to reduce the discrepancy between predicted Pc and G-function estimated Pc.
To this end, several datasets, each of which contain the same attributes, are collected from publications for shale and tight-sand formations. Part of datasets are selected for developing respective deviation terms, for shale and tight-sand, to be added to the empirical equation, while the remaining datasets are used to test the respective new equation. Then a regression analysis is performed between Pc differences and the individual petrophysical and mechanical properties for shale and tight-sand datasets separately. Eventually, two deviation terms have been derived and incorporated to the empirical equation, one for shale and another one for tight formations.
The deviation term for tight-sand formations correlate strongly with the rock mechanical properties, while the other with the rock mechanical properties and the formation porosity. Several field cases have been used to validate the empirical equation with respective deviation terms and the results show that the new formulae predict the fracture closure pressure with a relative absolute error less than 5% compared to those estimated from the G-function analysis for both the shale and the tight formations cases which are not used in developing respective deviation terms.
Diagnostic tools such as microseismic, microdeformation, and fiber optics have been successfully used in unconventional basins for many years to identify characteristics of hydraulic fractures (Warpinski et al. 2014). More recently there has been a push for integrating multiple diagnostics for better understanding of fracture characteristics and development for overall well planning and increasing ultimate recovery. Well spacing is crucial for proper development of each asset within every resource play in North America. The datasets used for this study will demonstrate how a more effective development of an asset based on well spacing can be created using integrated fracture diagnostic analysis to understand proppant distribution.
Zaluski, Wade (Schlumberger Canada LTD) | Andjelkovic, Dragan (Schlumberger Canada LTD) | Xu, Cindy (Schlumberger Canada LTD) | Rivero, Jose A. (Schlumberger Canada LTD) | Faskhoodi, Majid (Schlumberger Canada LTD) | Ali Lahmar, Hakima (Schlumberger Canada LTD) | Mukisa, Herman (Schlumberger Canada LTD) | Kadir, Hanatu (Schlumberger Canada Limited now with ExxonMobil) | Ibelegbu, Charles (Schlumberger Canada Limited) | Pearson, Warren (Pulse Oil Operating Corp) | Ameuri, Raouf (Schlumberger Canada Limited) | Sawchuk, William (Pulse Oil Operating Corp)
Enhanced oil recovery (EOR) is an economic way of producing the remaining oil out of previously produced Devonian Pinnacle Reefs in the Nisku Formation within the Bigoray area of Alberta. To maximize the recovery factor of the remaining oil, it was necessary to first characterize the geological structure, matrix reservoir properties, vugular porosity and the natural fracture network of these two carbonate reefs. This characterization model was then used for reservoir simulation history matching and production forecasting further discussed by (
Oil production from shale and tight formations will increase to more than 6 million barrels per day (b/d) in the coming decade, making up most of total U.S. oil production (> 50%). However, achieving an accurate formation evaluation of shale faces many complex challenges. One of the complexities is the accurate estimation of shale properties from well logs, which is initially designed for conventional reservoirs. When we use the well logs to obtain shale properties, they often cause some deviations. Therefore, in this work, we combine cores and well logs together to provide a more accurate guideline for estimation of total organic carbon, which is primarily of interest to petroleum geochemists and geologists.
Our work is based on Archie's equation. Resistivity log will lead to some incorrect results, such as total resistivity, when we follow the conventional interpretation procedure in well logs. Porosity is another complex parameter, which cannot be determined only by well log, i.e. density, NMR, and Neutron log. Therefore, the flowchart of TOC calculation includes five main parts: (I) the shale content calculation using Gamma log; (II) the determination of shale distributions using Density and Neutron logs and cross-plot; (III) the calculation of total resistivity at different distribution types; (IV) obtaining porosity using core analysis, NMR and density logs; and (V) the calculation of TOC from modified Archie's equation.
The results indicate that the shale content has a strong effect on estimation of water saturation and hydrocarbon saturation. Especially, the effect of shale content is exacerbated at a low water saturation. A more accurate flowchart for TOC calculation is established. Based on Archie's equation, we modify total resistivity and porosity by combining Gamma Log, Density Log, Neutron Log, NMR Log, and Cross-plot. An easier way to estimate porosity is provided. We combine the matrix density and kerogen density together and obtain them from core analysis. Poupon's et al. (1954) laminar model has some limitations when applying in shale reservoirs, especially at a low porosity.
Literature surveys show few studies on the flowchart of TOC calculation in shale reservoirs. This paper provides some insights into challenges of well logs, core analysis in shale reservoirs and a more accurate guideline of TOC calculation in shale reservoirs.
Rate-transient analyses (RTA) is a useful reservoir/hydraulic fracture characterization method that can be applied to multi-fractured horizontal wells (MFHWs) producing from low permeability (tight) and shale reservoirs. In this paper, a recently-developed three-phase RTA technique is applied to the analysis of production data from a MFHW completed in a low-permeability volatile oil reservoir in the Western Canadian Sedimentary Basin.
This new RTA technique is used to analyze the transient linear flow regime for wells operated under constant flowing bottomhole pressure conditions. With the new method, the slope of the square-root-of-time plot applied to any of the producing phases can be used to directly calculate the linear flow parameter,
The subject well, a MFHW completed in 15 stages, produces oil, water and gas at a nearly constant (measured downhole) flowing bottomhole pressure. This well is completed in a low-permeability, near-critical volatile oil system. For this field case, application of the new RTA method leads to an estimate of
The new three-phase RTA technique developed herein is a simple-yet-rigorous and accurate alternative to numerical model history-matching for estimating
Costin, Simona (Imperial Oil) | Smith, Richard (Imperial Oil) | Yuan, Yanguang (Bitcan Geoscience and Engineering) | Andjelkovic, Dragan (Schlumberger Canada) | Garcia Rosas, Gabriel (Schlumberger Canada)
Open-hole mini-frac tests are seldom performed in the Athabasca and Cold Lake oil sands due to the complexity of operations. In this paper we present the results of open-hole injections tests performed in Cold Lake, Alberta (AB), Canada. The objective of the injection tests was to assess the in-situ stress condition in the Cretaceous Colorado Group. The injection tests results combined with the run of formation image logs (FMI) before and after the injection have enabled not only the determination of the in-situ minimum stress in the rock, but also the full 3-D stress tensor, along with the orientation and inclination of the hydraulic fracture. The tests were performed in IOL 102/08-02-066-03W4 (N10 Passive Seimic Well, 'PSW'). The injection tests have revealed that the vertical stress in the area is the in-situ minimum stress, consistent with previous measurements. The hydraulically-induced fracture has sub-horizontal to moderate dip angle, mostly owing to the preexisting fabric of the rock, and peaks in the general NE-SW direction. Numerical modeling of the in-situ stresses has shown that the values of the vertical and the minimum horizontal stresses are close, with the vertical stress consistently being smaller than the minimum horizontal stress in all tested zones.
This paper outlines methods to characterize hydraulic fracture geometry and optimize full-scale treatments using knowledge gained from Diagnostic Fracture Injection Tests (DFITs) in settings where fracturing pressures are high.
Hydraulic fractures, whether created during a DFIT or larger scale treatment, are usually represented by vertical plane fracture models. These models work well in a relatively normal stress regime with homogeneous rock fabric where fracturing pressure is less than the Overburden (OB) pressure. However, many hydraulic fracture treatments are pumped above the OB pressure, which may be caused by near well friction or tortuosity but, may also result in more complex fractures in multiple planes.
Procedures are proposed for picking Farfield Fracture Extension Pressure (FFEP) in place of conventional ISIP estimates while distinguishing between storage, friction and tortuosity vs. fracture geometry indicators.
Analysis of FFEP and ETFRs identified in the DFIT PTA analysis method combined with the context of rock fabric and stress setting are useful for designing full-scale fracturing operations. A DFIT may help identify potentially problematic multi-plane fractures, predict high fracturing pressures or screen-outs. Fluid and completion system designs, well placement and orientation may be adjusted to mitigate some of these effects using the intelligence gained from the DFIT early warning system.