The Cliff Head is one of the most significant discoveries in the offshore Northern Perth Basin. Hence, understanding the structure and geology of the field is essential to further evaluate the offshore region in the basin. Two structural models were developed with the objective to achieve a better understanding of this field. The first model is focused on the Permian and older strata, while the second model is for the overburden. In addition, reservoir properties models (e.g. porosity model and water saturation model) were developed to better understand the reservoir facies and hydrocarbon distribution. Examination of the structural models has shown that there are two main sets of faults within the Cliff Head area, which can be categorized into the following: the deep Permian faults that are truncated against the Late Permian unconformity, and younger Cretaceous faults that were developed during the Early Cretaceous rifting. It has also shown that the oil accumulation within the field is structurally trapped within Permian aged set of horsts and is mainly reservoired within the Irwin River Coal Measures. The secondary target (e.g. the underlying High Cliff Sandstone) is mostly beneath the regional oil-water contact of −1257.8 m TVDss, except in the highest structural point in the field, where Cliff Head-6 was drilled. The Irwin River Coal Measures in the study area contained four high resolution depositional sequences that displayed a finingupward pattern as depicted by the Gamma Ray log response and are interpreted to have mainly deposited in a fluvial depositional system. The High Cliff Sandstone, in contrast, contained two high resolution depositional sequences that displayed a coarsening upward sequences as supported by Gamma Ray log response and were interpreted to have mainly deposited in marginal marine settings. Reservoir properties modeling was also conducted utilizing the 3D models, where a 3D porosity model was calculated and shows that the Irwin River Coal Measures, in general, exhibit higher porosity distribution than the underlying High Cliff Sandstone, even though the later has coarser and more laterally extensive sand sheets. This is probably attributed to diagenetic porosity reduction within the High Cliff Sandstone caused by the formation waters. The calculated 3D water saturation model also confirms the presence of a single regional oil-water contact within the field and hence, reservoir heterogeneities and fault seal capacities did not affect the hydrocarbon distribution within the field. Finally, all the calculated models (e.g. lithofacies model, porosity model, and water saturation model) were integrated to estimate the recoverable hydrocarbons in place, where the Cliff Head is estimated to contain a total of 15.2 million barrels.

The onshore Bahrain Field is a multi-reservoir oil and gas field in the Kingdom of Bahrain. Hydrocarbons are found in various stratigraphic intervals from Devonian to Upper Cretaceous in mostly carbonate reservoirs. Clastic reservoirs are scarce in the post-Permian section but dominate in the pre-Permian section. The Lower Cretaceous Kharaib Limestone is an oil reservoir. The unit was tested in different exploratory wells in the early life of the Bahrain Field and it was found to be of low permeability but produced oil. The first phase of field development in Kharaib was initiated in the 1970s and after an initial period of dry oil production, the wells produced for a long time with high water cut (more than 90%). In the early 2000s, a horizontal well drilled in the reservoir provided encouraging results. Main development activities started from 2010 onwards, after Tatweer Petroleum – Bahrain Field Development Company W.L.L. ("Tatweer Petroleum") was formed. Thirty horizontal and fifteen deviated producers (a total of forty-five wells) were drilled during the period 2010–2014 and as a result, oil production from the reservoir increased significantly. However, within a short period of time, most of the wells started producing with high water cut (more than 90%) and image logs recorded in many horizontal wells showed presence of fractures. Based on this observation and 3D seismic analysis, Kharaib was characterized as a fractured reservoir and high water production was attributed to it. Later on, many wells had mechanical failure due to casing corrosion developed against the shallower Shuaiba aquifer. All development activities were subsequently stopped for the reservoir due to economic risk. In 2016, a renewed effort was undertaken to analyze all past data including; regional tectonics, core data, 1970s build-up studies, cement integrity, and image log interpretations. This back-to-basics analysis indicated that the primary cause of high water production in the Kharaib wells is lack of zonal isolation with Shuaiba (casing corrosion wells excluded) and not due to the presence of occasional fractures. Development activities restarted in 2017 that focused on addressing the zonal isolation and casing integrity issues. Seven wells have been drilled to date producing with an average water cut of 22%. More development wells are planned in the future thereby giving a new lease on life to the reservoir.

Reverse time migration (RTM) involves zero-lag cross-correlation of forward extrapolated source function wavefields and backward extrapolated receiver wavefields. For a near surface with complex structures and velocity anomalies, forward propagating the source wavelet generates wavefields containing reflections, near-surface multiples, and scattered direct arrivals. The wavefields are recorded as upgoing arrivals contaminated by the same reflections, near-surface multiples, and scattered signals, which can be critical for imaging near-surface structures and scatterers. Here, we develop a new depth migration, duplex reverse time migration (DRTM) technique to improve imaging of complex near-surface structures. DRTM uses the direct arrival as a source to forward propagate and generate source wavefields, and reversely extrapolated recorded data in a zero-lag cross-correlation imaging condition to generate the final section. The interaction between the data components during cross- correlation can use primaries and multiples to image the near-surface structure correctly. Cross-talk artifacts may exist, but they are comparatively weak. DRTM is demonstrated on both synthetic and field data examples showing an enhanced image in areas with complex near-surface structures compared to conventional RTM imaging methods. The new algorithm can significantly enhance shallow imaging without additional computation costs compared with conventional RTM. It can produce an image with higher resolution and signal-to-noise (S/N) ratio by replacing the source wavelet with the recorded direct arrivals, which include near-surface information necessary to boost the image in areas with near-surface complexity. Since the direct arrivals are one of the most energetic events recorded, the resultant image is typically of high S/N. The wave can also illuminate shallow zones better than primaries in marine environments.

Objectives/Scope 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. The paper will also demonstrate the power of integrating wide-ranging data sources for effective well and reservoir management. Methods, Procedures, Process 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. Morphing (movie) software then interpolates the monthly images to create a smoothly transitioning "Heat Movie". Results, Observations, Conclusions 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. Novel/Additive Information 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.

High frequency asymptotic methods, based on solving the eikonal equation, are widely used in many seismic applications including Kirchhoff migration and traveltime tomography. Finite difference methods to solve the eikonal equation are computationally more efficient and attractive than ray tracing. But, finite difference solution of the eikonal equation for a point source suffers from inaccuracies due to singularity at the source location. Since the curvature of wavefront is large in the source neighborhood, the truncation error of the finite difference approximation is also significant, leading to inaccuracies in the solution. Compared to several proposed approaches to tackle source singularity, factorization of the unknown traveltime is computationally efficient and simpler to implement. Recently, a factorization algorithm has been proposed to obtain clean first order accuracy for tilted transversely isotropic (TTI) media. However, high order accuracy of traveltimes is needed for quantities that require computation of traveltime derivatives, such as take off angle and amplitude. I propose an iterative fast sweeping algorithm to obtain high order accuracy using factorization followed by Weighted Essentially Non-oscillatory (WENO) approximation of the derivatives. Although this method yields highly accurate traveltimes but it also results in increased computational load. Therefore, I propose a parallel fast sweeping algorithm to compute fast and accurate solution of the anisotropic eikonal equation. High accuracy is achieved first by using factorization followed by the WENO approximation of derivatives, whereas computational speed up is obtained by sweeping the computational domain in parallel. With a large number of CPUs, significant reduction in computational cost can be achieved for large 3D models. Numerical test shows improvements in accuracy of the TTI eikonal solution.

South Ordos sandstone reservoir is mainly featured by tiny pore, which mainstream throat radius is around 50nm, high filtration resistance, resulting in low oil productivity and more obvious non-linear seepage characteristics. As of low formation pressure, well production is poor and declines dramatically, therefore primary recovery is hard to sustain effective development for the reservoir. The core problem of tight oil development focuses on the evaluation of tight matrix flowing capability and reservoir producing condition. In the paper, in Ordos typical tight oil basin, by means of microscopic flowing simulation, numerical simulation as well as lab experiments results, single-phase and oil-water two-phrase flowing mechanisms have been analyzed, revealing tight oil single phase percolating resistance and movable oil saturation, providing key evaluation parameters for effective reservoir division. For oil-water two-phase flowing, Jamin effect is so serious that water flooding is hard to displace the oil in micro-pores, accordingly relative permeability and displacement efficiency are calculated. Tight matrix-fracture coupling model recovery mechanism have been analyzed, effective producing radius and mechanism of matrix are defined in the condition of fracturing horizontal wells developing, according to which productivity percentage of Ordos tight oil between fracture and matrix have been determined. On basis of geology evaluation and reservoir engineering analysis, correlation of geological properties-well dynamic characteristics are set up, then influencing factors have been studied to identify tight oil producing conditions on depletion development at different oil price. As different classified fracture developed in the reservoir, water flooding producing condition has been studied, laying the foundation for study of effective development method and technical strategy. Our research indicates that Ordos tight matrix is of low productivity, with movable water saturation increasing, well productivity sharp decline. During production period, production ratio from fracture is only amounted to 6~14% of accumulation oil. Fully excavating the potential of matrix reserves is predominant to achieve effective development of tight oil. Owing to high start-up pressure gradient, as high as 0.1~0.2MPa/m, for water flooding development, well spacing should be reduced to 50m□ to set up pressure response without fracture developing. While in Ordos basin natural fracture is developed, water channeling is so heavy that accumulative oil is lower than depletion method. CO2 start-up pressure gradient is far smaller than that of water flooding with composite EOR mechanisms, expected to be an effective injection medium for tight oil. It is a critical period how so many shut-in wells could be revitalized under low oil price condition. Relying on research results, Ordos tight oil new development method target has been determined, promoting application research and pilot test on CO2-gelled fracturing fluid and effective injection fluid sustaining matrix displacing pressure in tight oil development.

The Miocene deep sea turbidite sandstone of Burqan Formation is important hydrocarbon reservoir target in Midyan region, Red Sea, NW of Saudi Arabia. Excellently exposed outcrops of Burqan Formation in Midyan region provide good data to examine and evaluate the reservoir rocks. This study integrates field observations (sedimentologic, stratigraphic and structural) and measurements from outcrop analog of the turbidite sandstone to investigate and characterize the reservoir heterogeneity, quality and architecture. The methods and approach followed used sedimentologic and stratigraphic analysis based on vertical and lateral outcrop sections and photomosaic so as to reveal the vertical and lateral distribution of the lithofacies and their geometries at outcrop scale. Moreover, terrestrial laser scanning (LiDAR) was utilized in this study to capture outcrop meso to macroscopic sedimentologic and stratigraphic and structural features details (strata surfaces. geometry distribution, faults, fractures). We integrated field observations with laboratory analyses to characterize the microscopic sedimentologic heterogeneity of lithofacies, texture, composition and petrophysical properties of the turbidite sandstone. The stratigraphic analysis shows variation in outcrops from proximal to distal parts, within 15 to 20 km traverse across the outcrops belt (west to east) of Burqan Formation. The sandstone body thickness varied between 2 – 4 m in the proximal parts and between 0.5 – 1 m distally. Also, these variations in thickness was associated with increasing of shale/sandstone ratio from proximal to distal parts. The sandstone bodies width revealed from outcrop mosaics extend laterally between 100 to over 150 m. The lithofacies consists of both matrix and clast supported conglomerates, pebbly sandstone and coarse to very coarse and medium grained, massive, trough and horizontally stratified sandstone. These facies were interbedded with siltstone, mudstone and shale. The sand bodies were vertically and laterally stacked in the proximal parts and decreases in the medial and distal parts, however, locally the shale and mudstone lithofacies interbeds and form baffle zones. The region is tectonically and structurally active, therefore, at outcrop scale the repeated tectonics and rifting in the region resulted in faulting, shearing and fracturing which added complexity to the turbidite sandstone reservoir architecture. Moreover, tectonic affected reservoir/seal relationship, reservoir continuity and distribution of inter-reservoir barriers and baffles. The results of this high resolution outcrop analog study might provide information and data base on types and scales of geological heterogeneities and their impact on reservoir quality and architecture within the interwell spacing. Moreover, it might also provide guides for exploration and development and help in decision making to avoid risks under the complex geological setting in the Red Sea region and other hydrocarbon basins under similar geological setting.

We applied a recently introduced method to complete a feasibility assessment and design a stress testing campaign in a deep-water field in West Africa. We first reviewed the previous—and unsuccessful—campaign. Test data were inverted together with a priori knowledge from an independent geomechanical study to develop an understanding of the ambient conditions. Based on this understanding, the current campaign's chance of success (COS) was estimated to be 10%, with 1,000 psi of pressure capacity lacking to reach 95%. By analyzing the sensitivity of the risk to formation properties and design parameters, we identified various options to prevent this high, yet seemingly controllable, risk of test failure. Among them, a 1.7-ppg increase of mud density, expected to increase the COS to 80%, was deemed most effective and implemented. With 4 successful tests out of 10, the second campaign was more successful than the previous one. Yet this success rate was lower than anticipated. We inverted the second campaign's test data to revise our understanding of the in situ conditions. Our main findings are that, for this particular case, (i) the magnitude of the minimum horizontal stress was significantly higher than initially thought, (ii) the minimum horizontal stress and the horizontal stress ratio appeared to be anticorrelated, and (iii) the COS was extremely sensitive to the minimum horizontal stress. The conditions solved using the second campaign's dataset also explained the first campaign's negative outcome. This case study demonstrates that (i) the proposed planning method enables return of experience to be captured and leveraged from one test, or one series of tests, to the next, and the design of formation stress tests to be optimized, leading to an improved success rate of formation stress tests; and (ii) the proposed inversion scheme allows insight to be gained from both successful and unsuccessful tests, including in formation conditions other than the minimum horizontal stress.

Zubair Formation is one of the key producers in North Kuwait; however, the reservoir complexity and hydrocarbon movement along with pressure depletion always poses challenge for determining the perforation and completion strategy to optimize the production. Zubair Formation is broadly divided into three parts e.g. upper, middle and lower, the upper and lower units are of utmost importance for the current study. An integrated approach was adopted utilizing the high-resolution borehole image outputs; which has not only helped in identifying thin bedded reservoir zones but also facilitated the understanding of detail reservoir geology and sand dispersion. Integrated formation evaluation and workover design is always the key to sustain the production and it becomes even more important when the reservoir is highly heterogeneous in nature and coupled with declining pressure trend. Therefore, an innovative methodology was necessary to address the uncertainties. High resolution borehole images were utilized to determine the sand count, which can detect even the thinnest reservoir layer in the formation. Heterogeneity analysis was also performed to understand the relative sorting of the different reservoir units; sorting has a direct relation with reservoir permeability and thus reservoir productivity. High resolution sedimentary analysis was performed to understand the detailed sedimentology using the borehole image derived dip data; cross bedding types were identified which provides fair idea about depositional energy condition along with depositional environment. All the high-resolution inputs were integrated with openhole logs and volumetric results, which led to a clear deterministic picture of the reservoir, based on which crucial decision was taken. This integrated approach was adopted in three deviated well sections in Zubair formation, which has facilitated in improving the well performance. Detail sedimentary analysis and cross bedding typing in multiwell helps in fine tuning the sand dispersion in the reservoir model; which in turn found to be helpful for deciding future well locations.

In this paper, we present a procedure for high pressure resin impregnation of microporous rock. This procedure produces the high- quality pore casts that reveal the fine details of the complex pore space of micritic carbonates. We carefully test our resin impregnation procedure and demonstrate that it renders the high resolution, 3D confocal images of pore casts. In our work, we use silicon micromodels as a reference to validate the key parameters of high-pressure resin impregnation. We demonstrate possible artifacts and defects that might develop during rock impregnation with resin, e.g., the resin shrinkage and gas trapping. The main outcome of this paper is a robust protocol for obtaining the high-quality epoxy pore casts suitable for rock imaging with Confocal Laser Scanning Microscopy (CLSM). We have implemented this protocol and provided the high resolution, three-dimensional (3D) imagery and description of microporosity in micritic carbonates.

Simplified semi-quantitative equations are used in 1D geomechanics workflows to predict the rock’s behavior during drilling and production. While such methods allow for getting a time- efficient solution, it does lose out on accuracy. In addition, by simplifying equations, we limit our ability to predict behavior of the borehole wall only i.e. near wellbore solutions. We lose the ability to predict full field behavior in response to drilling and production activities. For example, when constructing a field-wide drilling plan or a field development plan for a complex subsurface setting, a simplified approach may not be accurate enough and on the contrary, can be quite misleading. A 3D numerical solution on the other hand, honours subsurface features of a field and simulates for their effect on the stresses. It generates solutions which are more akin to reality. In this paper, this difference between a simplified semi-quantitative well-centric approach (1D) and a full field numerical solution (3D) has been presented and discussed. The subsurface setting considered in the study is quite complex – an amalgamation of high dipping beds with pinch outs and low angled faults in a thrust regime. Wellbore stability and fault stability models have been constructed using both a well-centric approach and a full field-wide 3D numerical solution. It is clearly observed that field-based approach provided us more accurate estimation of overburden stresses, variation of pore pressure across the field, impending changes in stress magnitudes and its rotation due to pinch-outs and formation dips. For example, due to variation in topography, the estimated well-centric overburden at the toe of deviated well at reservoir level is lower by 0.21gm/cc (~1.75ppg~0.9psi/ft) as compared to the 3D model. It is also observed that within the field itself stress regime changes from normal to strike slip laterally across the reservoir. In comparison to 1D model, considerable differences in stable mud weight window of upto 1.5ppg is observed in wells located close to faults. This is primarily due to effect of fault on stresses (both magnitude and azimuth). Stress states of 4 faults were assessed and all 4 faults are estimated to be critically stressed with elevated risk of damaging three wells cutting through. However, a simple 1D assessment of stress state of faults at wells cutting through them, shows them to be stable. By comparing the differences between 1D and 3D solutions, importance of 3D numerical modelling over 1D models is highlighted.

An advanced wellbore stability analysis software product has been developed in-house at Aramco. This product offers three analysis modules: (1) the classical mechanical module (elastic); (2) the time-dependent analysis module (poroelasticity); and (3) the time-dependent analysis of naturally fractured rock module (dual-porosity and dual permeability poroelasticity). The stress and pressure analyses are integrated with four rock failure criteria (Mohr-Coulomb, Drucker-Prager, Modified Lade, and Hoek-Brown) to calculate critical mud densities. The basic mechanical module is similar to the wellbore stability module provided in the most-frequently-used drilling geomechanics software. What sets this product apart from the others is that no commercial drilling software to date has the time-dependent stress and pressure analyses modeled by this product's poroelastic and dual-porosity poroelastic modules, which can capture real-time phenomena introduced by the time-dependent fluid pore pressure perturbation and the wellbore time-dependent failures in tension and/or compression.

The location of producing intervals in multi-layer reservoirs and the determination of current formation pressures in these intervals are critical aspects of reservoir management. The identified not-producing layers in multi-layer wells can be activated to start contributing to the field production. Another challenge that grows over the time during the development of a mature multi-layer reservoir is excessive water production that can be caused either due to water breakthrough over some target layers (the edge water or water from nearby injectors) or can come along the channels in cement from a water-bearing reservoir, located above or below the target reservoir. This effect impacts the vertical sweep efficiency in the field and leads to early abandonment of the wells. The common solution to avoid it is to find the source of water and perform water shut-offs based on the pre-monitoring results. A specific technology has been worked out to detect fluid flows that happen both in well and reservoir. It is based on the analysis of data acquired by broadband high-definition spectral acoustic logging tool. The acoustic signal component produced by fluid flow through the rock matrix can be distinguished from other acoustic signals caused, for example, by wellbore or channel flows by its frequency features. The layer formation pressure was determined by numeric simulation using an empirical correlation between the reservoir fluid flow velocity, pressure gradient and the reservoir-related component of acoustic power. The interpretation results were used also to track, distinguish, and quantify flows behind pipe both in reservoir and through channels in cement. Multiphase sensors were used to determine phase composition inside the wellbore. This helped to identify the source of water in well production. Three tasks mentioned above - (1) location of producing layers, (2) determination of layer formation pressure, and (3) identification of water source in the well production - described in the paper was part of the field-monitoring programme carried out to optimize well production such as gas and water shutoffs, recompletion, switching from natural to artificial lift production, and others. The target is a sandstone oil reservoir consisting of many layers with variation of reservoir rock types, permeabilities, thicknesses and formation pressures in Cheleken Block, Turkmenistan. This paper presents survey results from a number of production wells being a part of 20-well logging campaign. Producing layers were identified in surveyed wells, with some of them equipped with sand screens, which made it difficult to identify producing intervals using conventional production logging tools. These results have been correlated with permeability model. The acquired spectral acoustic data showed that not all layers of the target multi-layer reservoir were producing. Additionally, the calculated layer formation pressure values were analysed and it was discovered that in the two wells producing from the same layers the top layer had a higher formation pressure than the others. The layer formation pressure values calculated using numeric simulations proved to be in a good agreement with the formation pressure measurement data, acquired in nearby infill wells. Regarding the water source, a case with successful remeadial job have been described. This paper demonstrates how the integrated logging suite complemented by acoustic and temperature logging tools can prove effective in identifying a water source in the complicated cases such as dual-completion wells producing from a multi-layer reservoir. The acquired information was used to increase the chances for successful remedial operations. Workovers performed based on survey results allowed eliminating water production in both wells. The evaluation methodology is cost effective because it does not require wells to be shut in and it can be applied riglessly. The acquired data and integrated evaluation logs can help the reservoir development team to optimize well performance and improve reservoir management in the field.

PETRONAS is interested in monetizing X Field, a high CO 2 carbonate gas field located in East Malaysian waters. Because of its location (more than 200 km from shore) and the preferable geological formation of the field, reinjection of produced CO 2 back into the field's aquifer has been considered as part of the field development plan. To ensure feasibility, the PETRONAS R&D team has conducted a set of laboratory analyses to observe the impact of CO 2 on the carbonate formations, through combining the use of static CO 2 batch reaction experiments with advanced helical digital core analysis techniques. The analysis of two representative samples, from the aquifer zone is presented here. The initial state of the samples was determined through the use of theoretically exact helical micro computed tomography (microCT) techniques. The images were processed digitally to determine the porosity and calibrated with RCA to ensure the reliability of digital core analysis results. After scanning, both plugs were saturated with synthetic brine with similar composition as the fields' formation brine and aged with supercritical CO 2 at reservoir temperature and pressure for 45 days. After 45 days, the aged core plugs underwent post reaction analysis using micro-CT scan and image processing software. Based on macroscopic observation, the core plugs showed no changes after aging with supercritical CO 2 at high pressure and high temperature (HPHT) as per reservoir condition. However, analysing the high resolution micro CT images, the team was able to determine the changes in porosity before and after CO 2 aging, which are around 1%.

Bahrain has begun exploring unconventional resources in the Khalij Al-Bahrain Basin for the Tuwaiq Mountain Formation. This work is a case study presenting the workflow for characterizing and modeling the unconventional development in Bahrain all the way from petrophysics through geology, completion modeling, and dynamic simulation. The work scope consisted of petrophysical modeling 10 key wells including calibration to core data. The petrophysics showed that the lower Tuwaiq Mountain interval with its TOC signature is remarkably consistent across all of Bahrain. The wells modeled in a 3D geological model with reservoir properties distributed throughout the reservoir to confirm resource in-place estimates published in early 2018. Well stimulation treatment on Well 1 was modeled and tied to the production test. A dynamic model was subsequently built to history match the production test. While not unique in its production match, this calibration is an important step for future optimizations in lieu of microseismic data. All of this information was used to form the basis for optimal completions to refine the next appraisal wells with forecasted production rates. The Tuwaiq Mountain reservoir has commercial potential in Bahrain, particularly in the western area where producibility has been proven. Producibility in the East has not been established as no production tests are available. In addition, future appraisal well locations were identified using the 3D geological model. The best trajectory was chosen such that the wells are estimated to yield EURs more than 500,000 bbls. The results of this project are important for Bahrain as it highlights the unconventional resource and production potential in the country. For the industry, unconventional development is in its early stages outside of North America and Bahrain’s case study can be utilized to expedite the learning curve in many other basins.

Differential compaction is an inherent process in carbonate systems that is thought to produce early natural fractures prior to any significant burial. Such fractures can persist and can be major permeability pathways, including areas of minor tectonic overprint. We forward model differential compaction fracturing in a carbonate reservoir in effort to predict the location of fractures in the subsurface. 3D finite-element geomechanical models are created to simulate differential compaction fracturing at a carbonate platform scale (kilometers) and the smaller carbonate build-up scale (10s of meters) commonly present within carbonate platforms. Interpreted seismic surfaces of key reservoir horizons are used as an input for the platform-scale model. Geometry of carbonate build-up from an outcrop analog is used for the build-up scale models. In both type of models layers identified to be compaction prone are restored to their expected pre-compaction state. A simplified mechanical stratigraphy scheme is adopted to distribute mechanical properties within the models consistent with their expected pre-burial properties. Geomechanical modeling in this study was applied to a field which includes two carbonate platforms at different stratigraphic levels. Modeling results predict increased fracture intensity at the windward margin of the carbonate platform. This coincides with increased windward-leeward asymmetry of an underlying older platform. Increased fracture intensity is predicted at the center of the platform where the underlying older platform displays significantly less asymmetry. Predicted fracture locations over the platform top also correspond with the location of carbonate build-ups identified from seismic data. Fracture observations from image logs and indirectly from mud loss data within the upper platform are consistent with our modeling results. Predicted areas of greatest fracture intensity correspond with the location of wells with the highest fracture intensity observed from image logs. Build-up scale models suggest that the build-up shape exerts a major control on the resulting differential compaction fracture pattern. Elongate build-ups tend to produce fractures oriented parallel to their axes. Circular build-ups tends to produce radial fracture patterns. Fracture orientation from image logs along with build-up shape observed using the coherence seismic attribute are consistent with these findings. This study offers a process-based fracture modeling approach that can enhance the predictability of the location and orientations of natural fractures in carbonate reservoirs.

The objective of this work is to establish a communication between the tight hydrocarbon-bearing formation and the wellbore by using high power laser technology. This paper presents different methods of utilizing the energy of the laser to enhance and improve the flow in unconventional reservoirs including tight formation, the successful results are used for field deployment strategy. High power laser is an innovative alternative to several currently used downhole stimulation methods and technologies. The system consists of the laser source which is mounted on the surface on a coiled tubing unit, fiber optics cable to transmit the energy and the downhole tool. The advantages of utilizing high power laser technology for downhole applications are the ability to control and orient the laser energy precisely. Laser energy generates heat when in contact with the rock samples, the heat impacts the rock samples by dehydrating, collapsing and dissociating some minerals near the wellbore, as well as creating micro- and macro fractures in the formation. In addition, heat removes the blockage around the wellbore and the effect extends deeper into the tight formation for production. Continues efforts over the past two decades have been proven that high power lasers provide controllable heat source while penetrating the formation, this mechanism enhances flow properties especially in tight formation. Low permeability in these formations restricts the flow and reduces production. Shale, Sandstones (including tight sandstones) and carbonate rocks have been treated with high power laser. Pre and post-treatment measurements are conducted for comparisons; the results from all rock types show improvement in permeability and flow. The results of advanced core characterizations, imaging and visualization are presented. The success of the lab experiments leads to the development of field deployment strategy to use high power laser for in-situ treatment in unconventional wells. Utilizing state-of-the-art high power lasers technology in downhole provides innovative and safe stimulation methods. Reliability, accuracy, and precision in controlling the power, orientation and the shape of the beam are some of the properties of the technology that made it attractive for downhole applications. Different tools have been developed for different applications that can fit any slim holes.

Monitoring of multi-stage hydraulic fractures in unconventional reservoirs has shown that some fractures are more effective and productive than others. Stress shadowing, in addition to reservoir lateral heterogeneity, are two potential factors behind this phenomenon. The focus of this study is to find the optimum hydraulic fracture spacing that aims to reduce the stress shadowing effect and ensure placement of hydraulic fractures in the best quality reservoir rock along the horizontal lateral. A base hydraulic fracture model was created for a well in the Eagle Ford reservoir. Fiber optic distributed acoustic sensing (DAS) data were analyzed to find the individual perforation cluster contribution to production based on the total proppant placed in each cluster. The modeled well cluster contribution and production data were then matched with actual data. Reservoir and geomechanical properties for certain stages of the horizontal wellbore were altered from the base model to address the effect of rock quality lateral variations. Four scenarios of 57 ft, 76 ft, 100 ft, and 142 ft spacing between perforation clusters were investigated to address the effect of stress shadowing. The sensitized reservoir and geomechanical properties include matrix permeability, Poisson's ratio, and Biot's coefficient. Increasing the matrix permeability from a base value of 0.2 ?D to 2 ?D caused the flowing fracture lengths to increase by 69%, 68%, and 48% in the heel, middle, and toe clusters, respectively. Stages with higher Poisson's ratio of 0.33, compared to a base value of 0.28, created larger flowing fracture lengths by 32% and 41% in the heel and middle clusters. Altering Biot's coefficient resulted in the same effect on flowing fracture lengths as altering Poisson's ratio. Overall, the rate of increase in flowing fracture lengths as a response to changing these properties was found to be more pronounced in the heel and middle clusters but less evident in the toe clusters. As for the cluster spacing scenarios, simulations showed that tighter spacing scenarios yielded a larger fracture network volume due to the higher number of clusters. However, these created fractures were less conductive than the ones created with wider spacing scenarios due to the stress shadowing effects. Production runs showed that scenarios with more accessed reservoir volume via more perforation clusters yielded a larger cumulative production over a 30-year simulation period.

Oil/gas exploration, drilling, production, and reservoir management are challenging these days since most oil and gas conventional sources are already discovered and have been producing for many years. That is why petroleum engineers are trying to use advanced tools such as artificial neural networks (ANNs) to help to make the decision to reduce non-productive time and cost. A good number of papers about the applications of ANNs in the petroleum literature were reviewed and summarized in tables. The applications were classified into four groups; applications of ANNs in explorations, drilling, production, and reservoir engineering. A good number of applications in the literature of petroleum engineering were tabulated. Also, a formalized methodology to apply the ANNs for any petroleum application was presented and accomplished by a flowchart that can serve as a practical reference to apply the ANNs for any petroleum application. The method was broken down into steps that can be followed easily. The availability of huge data sets in the petroleum industry gives the opportunity to use these data to make better decisions and predict future outcomes. This paper will provide a review of applications of ANNs in petroleum engineering as well as a clear methodology on how to apply the ANNs for any petroleum application.

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 Furongian-aged 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. The top of the Sajir Member of the Saq Formation is characterized by mud-rich bioturbated deposits which typically yield a distinct palynological assemblage (O5 Palynozone), characterized by dominance of morphologically distinctive sporomorphs (e.g., Virgatasporites spp., various hilate sporomorphs) and characteristic acritarch species such as ? Clypeolus sp., ? Cymatiosphaera sp., ? Retialetes sp., and Barakella spp. The assemblage is also characterized by the first occurrence of some typical Middle Ordovician acritarch taxa such as Arkonia , Striatotheca , and Frankea . Among the chitinozoan, Siphonochitina formosa is typically represented. The age of this assemblage spans the Dapingian to earliest Darriwilian, in agreement with faunal evidence. The assemblage indicates a marginal marine, restricted paleoenvironment. Virtually identical palynological assemblages occur in Oman in the Saih-Nihayda Formation, considered of late Dapingian to Darriwilian age. More specifically, it is suggested here that the O5 Palynozone of Saudi Arabia permits correlation of the upper Sajir Member of the Saq Formation with the lower, sand-prone, part of the Saih Nihayda Formation in Oman.