The basic objective of this course is to introduce the overview and concept of production optimisation, using nodal analysis as a tool in production optimisation and enhancement. The participants are exposed to the analysis of various elements that help in production system starting from reservoir to surface processing facilities and their effect on the performance of the total production system. Depth conversion of time interpretations is a basic skill set for interpreters. There is no single methodology that is optimal for all cases. Next, appropriate depth methods will be presented. Depth imaging should be considered an integral component of interpretation. If the results derived from depth imaging are intended to mitigate risk, the interpreter must actively guide the process.
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.
Bertolini, Andre Carlos (Schlumberger) | Monteiro, Jacyra (Schlumberger) | Canas, Jesus A. (Schlumberger) | Betancourt, Soraya S. (Schlumberger) | Mullins, Oliver C. (Schlumberger) | Colacelli, Santiago (Schlumberger) | Polinski, Ralf K. (Schlumberger)
The objective of this study is to characterize fluid distributions in a presalt field by using well data including downhole fluid analysis (DFA) from wireline formation testers (WFT), openhole logs, and a simplified structural/geological model of the field. From an understanding of the petroleum system context of the field, reservoir fluid geodynamics (RFG) scenarios are developed to link the observations in the existing datasets and suggest opportunities to optimize the field development plan (FDP).
DFA measurements of optical density (OD), fluorescence, inferred quantities of CO2 content, hydrocarbon composition, and gas/oil ratio of fluids sampled at discrete depth in six presalt wells are the basis of this study. DFA data at various depths captures fluid gradients for thermodynamic analysis of the reservoir fluids. OD linearly correlates with reservoir fluid asphaltene content. Gas-liquid equilibria are modeled with the Peng-Robinson equation of state (EOS) and solution-asphaltene equilibria with the Flory-Huggins-Zuo EOS based on the Yen-Mullins asphaltenes model. OD and other DFA measurements link the distribution of the gas, liquid, and solid fractions of hydrocarbon in the reservoir with reservoir architecture, hydrocarbon charging history, and postcharge RFG processes.
Asphaltene gradient modeling with DFA reduces uncertainty in reservoir connectivity. The CO2 content in some sections of the field fluids limits the solubility of asphaltene in the oil, and the small asphaltene fraction exists in a molecular dispersion state according to the Yen-Mullins model. Low values of OD and small asphaltene gradients seen in most of the upper zones reflect the small asphaltenes concentration in the crude oil. The CO2 concentration was modeled with the modified Peng-Robinson EOS in good agreement with measurements in upper reservoir zones. Matching pressure regimes and asphaltene gradients in Wells B and C indicate lateral connectivity. The hydrocarbon column in this part of the reservoir is in thermodynamic equilibrium. In Wells A, C, D, E, and F the OD of the oil indicates an asphaltene content increase by a factor of four at the base of the reservoir as compared with the crest of the reservoir. This tripled the viscosity in Wells C and D, as indicated by in-situ viscosity measurements. The accumulation of asphaltenes at the bottom of the reservoir is most likely driven by a change in solubility resulting from thermogenic CO2 diffusion into the oil column from the top down.
The challenge of the limited number of wells in the development phase of a presalt field for obtaining data to evaluate reservoir connectivity before the FDP is ably addressed by deploying the latest WFT technologies, including probes for efficient filtrate cleanup and fluid properties measurement. These measurements and methodology using a dissolved-asphaltene EOS enabled developing insightful RFG scenarios.
A regional study of the Burgan formation has been carried out over the North Kuwait Fields to understand the variation in depositional environment, oil occurrence and control of trapping mechanism on the quality of oil. The Burgan Formation in North Kuwait comprises fluvial, deltaic and marine sediments deposited during the Lower Albian period in response to global changes in sea level. There is a systematic gradation of depositional environments in Burgan during this period. Oil entrapment in this formation shows regional variation. Both stratigraphic and structural controls on oil accumulation are dominant in the region. The oil quality becomes heavier towards North and has a strong structural control. Significant volume of inplace oil has been estimated during this study which would be pursued for commercial exploitation of this deep heavy oil reservoir.
Burgan clastic sedimentation over Shuaiba carbonates was initiated by a regional fall in sealevel and establishment of a deltaic setting. Reservoir facies include mouth bars and distributary channels along with non-reservoir facies of interdistributary bay and shallow marine environments. After a significant hiatus, the braided channel systems with massive amalgamated sand bodies were established in response to significant fall in seal level. Subsequently a significant marker in form of a marine and shoreface sand with associated marine shale was deposited with a rise in sea level. Estuarine channels and bay shales were deposited above this surface. The upper part of Lower Burgan has transgressive sand bodies. The Middle Burgan is dominated by marine shale and shoreface sand deposits in response to further rise in sea level. The Upper part of Burgan is mainly comprising estuarine channel sands and interdistributary bay deposits. In a regional context, the sedimentation pattern shows increasing marine influence to East-Northeast directions.
The oil quality in Burgan is intricately related to the structure and trapping mechanisms. A post Mishrif time tilt in structure has resulted in a deeper relict oil water contact in Lower Burgan towards West of Sabiriyah. In the area towards North of Raudhatain structure, the fluid contact shows significant tilt towards North with a rising structure. The doubly plunging anticlines of Raudhatain and Sabiriyah structures have lighter oil in Burgan formation in a structural trap. Further north of Raudhatain, the oil is heavy although there is lateral reservoir continuity. Significant faults have been mapped in this area. The structure is shallower towards North with progressively deeper fluid contact in Lower Burgan. Origin of heavy oil appears be due to significant spilling of lighter oil along faults and upstructure migration due to structural tilting and transtensional deformation.
Significant accumulation of heavy oil has been established in Basal Burgan, Lower Burgan and Upper Burgan Formations. Heavy oil inflow in form of testing and sampling is seen in 12 wells. Aggressive plans are in place to map the oil quality and to formulate a long term exploitation strategy.
Franquet, Javier (Baker Hughes, a GE company) | Shaver, Michael (ADNOC Offshore) | Edwards, Ewart (ADNOC Offshore) | Neyadi, Abdulla Al (ADNOC Offshore) | Noufal, Abdelwahab (ADNOC Upstream) | Khairy, Hamad (Baker Hughes, a GE company)
A pilot was drilled offshore Abu Dhabi aiming to determine the in-situ stress magnitudes. A time-dependent reactive shale formation separates Middle and Lower Cretaceous Limestone formations, leading to difficult open-hole logging conditions. Determining the stress regime and stress contrast across these formations is critical for assessing wellbore stability in extended-reach wells, setting casing shoe depths, and designing hydraulic fracturing in the tight reservoirs. Therefore, a comprehensive logging including multiple in-situ stress measurements and full-core was acquired.
Seven microfrac stress measurements were obtained in one pipe-conveyed straddle-packer run conducted in a 15°-degree deviated 8½-in. open-hole wellbore. Each microfrac test was designed with multiple pressurization cycles to accurately obtain the closure stress away from the near-wellbore zone. Core and logging data from offset wells were used to calibrate the pre-job microfrac assessment. Real-time data monitoring was implemented for quality-control and tool operation decisions while logging. Three different pressure-decline analysis methods were used to identify the fracture closure: (i) SQRT square-root of time, (ii) G-function, and (iii) Log-Log plot on each microfrac station.
The pilot well required an inhibited oil-based mud system to stabilize the 360-ft. water-sensitive shale formation. All microfrac stress measurements successfully reached the formation breakdown pressure, providing clear propagation and fracture closure identification. The three pressure decline methods produced results around ± 15 psi from each other with G-function predominately higher and Log-Log predominately lower than the SQRT. These microfrac tests measured minimum horizontal stress gradients between 0.67 to 0.77 psi/ft confirming the normal faulting stress regime in the studied reservoirs and a near strike-slip stress regime in the intervening shale formations. The formation breakdown, fracture reopening and closure pressure provide an accurate present-day tectonic model with ~0.1 and ~0.9 mStrain in the minimum (N80°W) and maximum (N10°E) horizontal stress directions in the absence of breakouts and induced fractures on image logs. The Lower Cretaceous tight reservoirs, identified as generally thin (<10-30ft) and low-quality (<10mD, locally <1mD) microporous carbonates, were located between low stress contrast (0.69 psi/ft) clay-rich limestones intervals in the overburden and high stress contrast (0.74 psi/ft) denser dolomites and clean tight limestones in the underburden.
The risk of tool plugging and unsuccessful latching due to large particle solids in the mud was mitigated by multiple mud filters and repeated circulations while running-in hole with the straddle packer module. The microfrac tests in the Lower Cretaceous tight reservoirs provide the stress contrast measurements to properly evaluate hydraulic fracture containment on these tight reservoirs for future field development plans.
An updated geological and dynamic model for a giant Middle East carbonate reservoir was constructed and history matched with the objective of creating an alternative model which is capable of replicating the reservoir production mechanisms and improving predictability, allowing optimizing the field development plan and water injection strategy. Giant Middle East carbonate fields often have long production history and exhibit high reservoir heterogeneity. It is always challenging to get a robust history matched model aligned with geological concepts and dynamic behavior understanding.
The objective of this paper is to present an improved and integrated reservoir characterization, modeling and history matching procedure for a giant Lower Cretaceous carbonate reservoir in the Middle East. The applied workflow integrates all available geological data (stratigraphy, depositional facies, and diagenesis), petrophysical data (RCA and minipermeameter data, Petrophysical Group definition, cut-off definition) and the extensive database of dynamic data (long production history, well test, RST, open-hole log saturation over more than 40 years of development drilling, and MICP). The process was initiated with the reservoir review by means of a fully integrated study that allowed having better understanding of the reservoir behavior and production mechanisms. The key heterogeneities (high permeability and intra-dense layers) which control the flow behavior were identified during this process. Geological trend maps were generated to control the distribution of high permeability and intra-dense in the model. Well test data, open-hole logs from development wells and time-lapse saturation logs from observation wells were used to calibrate the trend and permeability log data. A phenomenological model was constructed to test the main factors impacting the production mechanism as identified during the reservoir review. Multiple iterations were performed between the static and dynamic models in a way that allowed a quick and efficient work that is consistent with all disciplines assumptions.
Such continuous loop between the dynamic and geological models, with focus on the geological heterogeneities driving the dynamic reservoir behavior, has led to a more robust model capable of replicate the production mechanisms, which represents a major improvement compared to previous model in term of predictability.
Khan, Riaz (ADNOC Onshore) | Salib, Mina Sameh (ADNOC Onshore) | Ba Hussain, Ali (ADNOC Onshore) | Bin Abd Rashid, Atiqurrahman (ADNOC Onshore) | Aydinoglu, Gokhan (ADNOC Onshore) | Farooq, Umer (ADNOC Onshore)
In this study field, the objective was to identify the causes of low resistivity pay that was limited towards the southwest of the field. Restricting the focus only on diagenesis has not yielded conclusive explanations to delineate the affected area. Alternatively, investigating the influence of structural evolution (folding and tilting) on hydrocarbon charging mechanism and diagenesis has significantly contributed to a reasonable explanation. This, in turn, can potentially impact decisions related to reservoir characterization and field development planning.
The field has adequate coverage of data from vertical (appraisal and observers) and horizontal wells (producers and injectors). The approach of structural flattening at different time intervals was applied in understanding the structural evolution of the field as part of regional tectonic history of the area. The delineation of areas in different paleo-positions has helped in grouping Wells into categories for thorough investigation. Detailed analyses of conventional and advanced logs, and core data were performed which included: petrographic analysis, pore throat and bound water evaluation, and assessment of resistivity log signatures in reference to the paleo-positions of the Wells.
The structural evolution and corresponding hydrocarbon charging mechanisms (drainage and imbibition) have influenced the reservoir hydrocarbon saturation in the field from northeast to southwest. The northeast tilting was triggered by Zagros loading, combined with thermal uplift associated with Red Sea opening. This resulted in imbibition in the extreme northeast and second phase of primary drainage in the extreme southwest of the field. As a result, the area that was previously in water leg during early Tertiary provided more exposure to diagenetic processes which enhanced the total porosity (up to 5p.u.) with high bound water and low resistivity pay. The areal coverage within water leg has been well defined in this study by evaluating the positions of paleo structural closures and hydrocarbon charging mechanisms. This would be useful in capturing diagenetic overprint in properties modeling as well as defining appropriate rock types for better saturation height function and volumetric estimations in this area. Consequently, the field development strategy was to develop the central area, in the first phase, since it was less affected by fluids saturation variations caused by the structural evolution. The study has provided improvement in reservoir characterization techniques for well placement and enhanced field development planning.
The methodology and approach used in this study are usually applied, to some extent, during exploration stages or basin modeling at regional scale with limited data availability and it is not utilized enough for Well placement and reserves estimations in the development stage. The approach applied here, with substantial data availability and integration, can potentially help in making decisions in the early development stage, allow successful field commissioning, and achieve initial production performance and target plateau.
Taher, Ahmed (ADNOC Upstream) | Celentano, Maria (ADNOC Upstream) | Franco, Bernardo (ADNOC Upstream) | Al-Shehhi, Mohammed (ADNOC Upstream) | Al Marzooqi, Hassan (ADNOC Upstream) | Al Hanaee, Ahmed (ADNOC Upstream) | Da Silva Caeiro, Maria (ADNOC Upstream)
In early Aptian times, subtle tectonic movements may have been activated along the NW-SE strike-slip faults and have resulted in a vertical displacement along these faults. The displacement would have allowed the carbonate-producing organisms to colonize along the shallower southern margin and generate well developed reservoir facies. The basinal facies were deposited to the north of the shelf margin, which is known to be the Bab Basin.
Significant oil was discovered in the Shuaiba shelf facies. However, the lagoonal and basinal facies have potential for discovering a significant volume of hydrocarbon, especially in the fields that are located in the Upper Thamama hydrocarbon migration pathways. This potential is supported by the absence of an effective seal separating Thamama Zone-A from Shuaiba basinal facies above, which allowed for the Zone-A hydrocarbon to migrate vertically into the Shuaiba basinal facies. In addition, this potential was supported by the hydrocarbon shows while drilling and by the interpreted well logs, which confirm the presence of movable hydrocarbon in the Shuaiba lagoonal and basinal facies.
The Shuaiba Formation is comprised of two supersequences (
The Shuaiba basinal facies were deposited in an intrashelf basin that was enclosed by the Shuaiba shelfal facies sediments. This resulted in restricted water circulation, anoxic condition and deposition below the wave base. Such depositional environment is favourable for source rock preservation.
Lithologically, Shuaiba basinal facies consist of pelagic lime-mudstone, wackestone and packstone with abundant planktonic microfossils. These facies are characterized by low permeability values, but their porosity can reach up to 20%. The lagoonal sediments consists of a deepening sequence of carbonate sediments, with shallow marine algal deposits at the base and fine hemipelagic to pelagic carbonates in the upper section.
The differences between the Shuaiba Shelf and the Shuaiba Basin are mainly in permeability values. By applying the latest technology in horizontal drilling and hydraulic fracturing, the Shuaiba basinal facies will produce a significant volume of hydrocarbon.
The field was discovered in 1992. It produces oil and associated gas from two reservoir sub units of the Upper Shuaiba USh3F1 and USh3F2, and exhibits both structural and startighraphical traps. The reservoir units are compartmentalized by NW-trending normal faults into five fault blocks within the same field towards the North East. They are vertically separated by non-reservoir low permeability mudstone facies. US3F2 is setting above Orbitolina shale. The objective is to build a new geological model in a very complex carbonate reservoir, to allow for better reservoir development, and adding new field opportunities using state of art seismic data.
Lower unit (US3F2) consists of an aggradational sequence skeletal peloid-foram packstone/wackestone, and in-situ rudist-algal boundstone/packstone build-ups, which is localized to the NE-trending axis of the field. These sequences are deposited in a low to moderate energy environment. US3F2 reaches a maximum thickness of 50 ft in the rudist build-ups, but the width of the rudist-algal boundstone facies parallel to depositional dip (SE) is only 0.5–0.7 km. Cores exhibit abundant secondary porosity with an average of 30% and permeability up to 700 mD suggesting early subaerial exposure and leaching.
Upper unit (US3F1) is either absent or very thin across the crest and thickens to over 20 ft basinward; downdip, it is separated from US3F2 by a shale unit. US3F1 consists of an upward-shallowing deposits of Orbitolina mudstone, reworked stromatoporoid-rudist floatstone, small rudist floatstone, and fine skeletal grain-dominated packstone with rudist fragments.
3D model was generated covering large area of about 15x9km of the field. The new seismic horizon and faults interpretation were used in the 3D structural modeling. Cores descriptions and photos were used to define core facies, depositional environments and vuggy intervals. Rudist buildups direction of progradation was also defined based on BHI.
Reservoir rock Fabric number (RFN) was defined based on Lucia method and populated using veriogram per zone for the vertical wells using moving average method followed by Gaussian Random simulation, co-kriged with the moving average properties as a trend, for both vertical and horizontal wells. Porosity was populated with the same method. Water saturation and permeability were calculated using Lucia height function method.
Understanding of the reservoir heterogeneity, architecture and 3D modeling using RFN based on Lucia method allowed a better distribution of reservoir properties to be used in dynamic simulation for better history match, predict waterflood performance and adding new development areas.
Salahuddin, Andi A. B. (Abu Dhabi National Oil Company, Onshore) | Khan, Karem A. (Abu Dhabi National Oil Company, Onshore) | Al Ali, Reem H. M. (Abu Dhabi National Oil Company, Onshore) | Al Hammadi, Khaled E. (Abu Dhabi National Oil Company, Onshore)
This paper described the novel approach for stochastically modeling complex carbonate reservoir lithofacies and properties distribution within a High Resolution Sequence Stratigraphy (HRSS) framework. The carbonate lithofacies discussed in this paper contains heterogeneous pore types and properties. The reservoir displays an extensive range of geologic and petrophysical properties that make the efficient recovery of hydrocarbons is a challenging task. Hence one of the key steps in improving the recovery factor is by defining the three dimensional variability patterns in the reservoir in the form of fine geocellular static model. The key static geological elements that must be well defined are HRSS framework, lithofacies architecture, and field wide rock properties.
Subsurface analysis was done by examining 600 feet core footage from more than 15 wells, conventional logs from more than 50 wells, and more than 350 thin sections. The reservoir section averages 35 feet that can be subdivided into 6 high-frequency sequences. The reservoir consists of lagoonal packstone-rudstone, grain rich ooid-peloid shoal, and rudstone-boundstone mid-ramp. The shoal deposits exhibit the best permeability and oil saturation and it consists of discontinuous lithofacies body that depicts locally excellent porosity and permeability characteristics.
Lithofacies geometry and properties studies must form a fundamental basis for characterizing and modeling HRSS framework and lithofacies architecture variability through the reservoir. Combined with wireline-log data, they provide a basis for defining both reservoir framework and rock attribute distributions.
Complex lithofacies geometries and transitions, both vertically and laterally between the mound and discontinuous grain-rich ooid-peloid shoal lithofacies together with the continuous and sequential lagoonal and mid-ramp lithofacies does not allow to simulate these sorts of lithofacies assemblage using single lithofacies model algorithm. Hence a new holistic approach was implemented. A combination of Object Based (OB) algorithm and Truncated Gaussian Simulation (TGS) algorithm was employed to handle the complex lithofacies transition. This enables generating multiple realistic field wide lithofacies distribution and relationship which aligns with data trend, subsurface analog in the nearby fields, as well as that is from the outcrop exposure. The established lithofacies distribution within HRSS framework was then used to constrain field-wide properties and diagenetic trend and distribution in the reservoir.
This new holistic approach has recently been successfully implemented in the studied field. The resulted geostatistical model was able to explain pressure depletion and production rate as shown in historical production data of the field. The resulting dynamic model will hence provide reliable production forecast and reservoirs development plan which will eventually allow accomplishing the mandate recovery target.