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The Vaca Muerta (VM) formation, one of the largest unconventional reservoirs worldwide located in the Neuquén basin, has ceased to be a promise and is becoming a venturous reality. During recent years, the investments in its development have increased significantly. By the year 2040, it is believed that the VM formation may generate 560,000 bbl of liquid and 6,000 million cubic feet of gas per day.
One of the primary challenges of many operators has been to select the most productive landing zones; consequently, the performance of an accurate and complete petrophysical evaluation of the reservoir has become vitally important to increase production and to optimize well completion costs. The evaluation of shale formations using electrical logs is a major challenge for most petrophysicists because many of the measurements from the logging tool are affected by the organic matter concentrated in this type of rock.
This paper highlights the way in which these challenges were addressed. It describes the logging operation, as well as the integral petrophysical interpretation performed for a pilot well located in the oil window of the VM formation.
The key element for the success of this work was the implementation of the integrated workflow to evaluate the potential of the shale oil well. The integrated workflow enabled the identification of hydrocarbon-bearing formations, quantification of reservoir properties and hydrocarbons in place, determination of lithology variations within the objective section, and establishment of reliable correlations between electrical logs and the organic richness of the VM formation. In addition, the assessment of geomechanical properties has become vitally important to optimize well placement and to select the best hydraulic fracturing design.
The integrated analysis of the pilot well presented in this paper has proven to be a successful case in which an effective characterization of the VM formation, following the proposed formation evaluation workflow, and the integration of wireline data with the various data acquisition program components, enabled the delivery of recommendations about the prospective interval in which to land the programmed lateral well.
Ultra-high-pressure high-temperature (uHPHT) reservoirs undergo extreme pressure depletion during their production life cycle. This results in significant reservoir compaction and consequent overburden subsidence with major consequences for wellbore mechanical integrity, safety, and field economics. However, the use of underdetermined geomechanical models to accurately predict compaction-induced stress/strain changes on wellbores and its consequences during production time results in significant residual uncertainty. One method of measuring compaction-induced stress/strain changes in wellbore is by the emplacement and measurement of radioactive markers. Although it is long established in normal pressure reservoirs, it is rare in uHPHT projects.
The Culzean uHPHT gas-condensate field is located in the UK Central North Sea. To constrain geomechanical model compaction uncertainty, radioactive markers were deployed. The objective was to accurately acquire preproduction baseline measurements and subsequent changes through periodic measurements during production life. These accurate wellbore measurements would then be compared with the geomechanical model to help calibrate predicted to actual compaction. By doing so, the objective is to enable better informed decisions regarding well and field management. The Culzean uHPHT radioactive marker project comprised a planning phase and a preproduction safe deployment including a baseline survey phase. Subsequent repeat measurements are planned during field production life.
The emplacement and surveying of the subsurface radioactive markers for compaction monitoring in uHPHT reservoirs is a high value but nontrivial operation. In addition, much knowledge and experience of the methodology has been lost. This paper contributes to published literature by describing the successful emplacement and monitoring of subsurface radioactive markers on Culzean and aims to capture learnings and knowledge for future workers. Early detailed planning coupled with extensive testing is key to successful deployment. Timely engagement of all stakeholders and ensuring all decisions are aligned with safety and environmental considerations also contribute to realization of the project aims.
Mishra, Anoop Kr. (ADNOC Offshore) | Albooshi, M.A (ADNOC Offshore) | Al Ali, Ahmed Ebrahim (ADNOC Offshore) | Sinha, Rakesh (ADNOC Offshore) | Al Hashmi, Ghassan (ADNOC Offshore) | Al Blooshi, Abdulla (ADNOC HQ) | Mills, Carey (ADNOC HQ) | Mandl, Johannes (ADNOC HQ) | Fernandes, Warren (BHGE) | Potshangbam, Sanathoi (BHGE) | Abdoun, Safwat (BHGE) | Hassan, Syed (BHGE)
Accurately placing a horizontal appraisal well within an interbedded reservoir sequence presents a wide range of challenges especially when there is a lack of nearby control wells. These challenges relate to uncertainties in the formation (dip, reservoir continuity & porosity development) and reservoir fluids (contact depth, transition zone height). In order to achieve the appraisal objectives it was critical to successfully intersect certain zones within the reservoir sequence and ascertain their hydrocarbon flow potential along with quantifying key reservoir properties and fluid boundaries. This data was essential for defining and optimizing the subsurface components of field development planning including well count, expected flow rates and in- place / recoverable resource estimations.
In this particular application the target reservoirs are porous gas saturated carbonates developed within an interbedded Jurassic aged limestone. Well placement in the subject well had the primary objective of intersecting five HC bearing zones while maintaining a safe distance from a conductive zone interpreted to be water saturated. As part of the pre-well planning, 3D real-time multiwell reservoir modelling and its updating capabilities with appropriate LWD measurements for Proactive Geosteering and Formation Evaluation was planned. Based on forward response model from offset well data along with drilling engineering and data acquisition requirements, an LWD suite consisting of RSS, Gamma Ray Image, High Resolution Resistivity Image (Fracture and Fault identification), Neutron, Density and 16 sector Density image along with a Deep Azimuthal Resistivity measurement for early detection and avoidance of conductive/water zones was utilized. This tool is capable of early detection of conductive zones that could indicate either transition zone saturations or water saturated porosity beneath a gas-water contact (GWC).
Application of the Azimuthal Resistivity measurements along with the realtime updates of the subsurface model helped place the appraisal well within the hydrocarbon column and also established the top of the low resistivity "Wet Zone". Importantly, these results were later confirmed with production logs acquired as part of well testing operations.
Ramatullayev, Samat (Schlumberger) | Blinov, Vlad (Schlumberger) | Tukhtaev, Rustam (Schlumberger) | Filimonov, Anton (Schlumberger) | Mendybaev, Nurhat (Schlumberger) | Zeybek, Murat (Schlumberger) | Tillyabaev, Muzafar (Surhan Gas Chemical Operating Company LLC) | Abidov, Khurshid (Surhan Gas Chemical Operating Company LLC) | Gavrilov, Alexey (Surhan Gas Chemical Operating Company LLC) | Frik, Vladimir (Surhan Gas Chemical Operating Company LLC)
Carbonate reservoirs can exhibit heterogeneity in terms of porosity, permeability, fractures, vugs and wettability. This heterogeneity affects well performance, completion and reservoir management development decisions. Although extensive logs are run for the petrophysical evaluations in these formations, the use of advanced wireline formation testers (WFTs) can greatly aid in reservoir description. WFT not only can identify hydrocarbon bearing formations but also plays a vital role in fracture characterization and calibration of fracture models.
Advanced petrophysical logs were used to identify potential pay intervals, while high resolution image logs to delineate fractured zones and static fracture parameters, such as dip, azimuth and aperture. It has been shown that fracture dynamic properties, such as conductivity, can be quantified via pressure transient analysis using wireline formation tester in addition to fluid analysis. In this paper, WFT data was used to understand the pressure behavior of naturally fractured reservoir containing a network of discrete finite-conductivity fractures.
The study presents results obtained from advanced logging suite that was run to characterize complex low porosity and low permeability carbonate reservoir where natural fractures provide primary pathways of fluid flow. Advanced wireline formation tester with straddle packer and fluid analyzer were used to test potential intervals. Two out of several intervals were enabled to flow, identifying mobile gas. The pressure transient response confirmed the complexity of reservoir and dominant contribution to flow regimes from fractures in these two intervals. Dynamic fracture properties were characterized through pressure transient analysis and were integrated into fracture model. On the other hand, flow could not be established in number of other intervals indicating tight matrix and no flow contribution from fractures, leading to calibration of geological models.
The novelty of approach is the use of wireline formation tester not only to measure formation pressure and acquire downhole samples but to characterize dynamic fracture properties to calibrate fracture model.
Saleh, Khaled (Kuwait Oil Company) | Al-Khudari, Abdulaziz (Kuwait Oil Company) | Al-Azmi, Mejbel Saad (Kuwait Oil Company) | Al-Otaibi, Fahad Barrak (Kuwait Oil Company) | Patnaik, Chinmaya (Kuwait Oil Company) | Joshi, Girija Kumar (Kuwait Oil Company) | Abdulkarim, Anar (Halliburton) | Aki, Ahmet (Halliburton) | Fahri, Nadir (Halliburton) | Sanyal, Aniket (Halliburton) | Sainuddin, Shahrin (Halliburton) | Clarion, Benjamin (Halliburton)
Directional wells through the 6-in. production hole sections in the Marrat reservoir of the Jurassic formations have traditionally required several wireline logging and hole conditioning runs for comprehensive petrophysical interpretation and completion design.
As the planned well inclinations increase to maximize reservoir exposure and sweep efficiency, WL deployment poses significant challenges due to increasing risk of losing the bottom hole assembly (BHA) in the hole. Over time, Logging-While-Drilling (LWD) tools have become preferable for the asset team, where the tools are run either with the actual drilling BHA or within a dedicated wiper trip after the section has been drilled to total depth (TD). Using LWD tools in this application also reduces well delivery times and costs.
A comprehensive logging solution was required to drill the 6-in. reservoir section of a study well. The complex LWD string consisting of gamma ray, resistivity, neutron porosity, azimuthal density, azimuthal sonic, and Nuclear Magnetic Resonance (NMR) tools was deployed on a Motorized Rotary Steerable System (MRSS) BHA. In addition, a prototype high-resolution acoustic imaging and caliper tool, designed to be run in both water-based mud (WBM) and oil-based mud (OBM), was also included. The acquired logging data was used for enhanced formation evaluation. Fracture and borehole breakout interpretation from the image data played a key role in successful completion design.
This ultimately led to Kuwait’s first successful “hexa combo” LWD drilling run and the country’s first LWD ultrasonic imaging tool run in OBM in this hole size, with 13.3 ppg OBM with a maximum downhole temperature of 275ºF.
BinAbadat, Ebtesam (ADNOC Offshore) | Bu-Hindi, Hani (ADNOC Offshore) | Al-Farisi, Omar (ADNOC Offshore) | Kumar, Atul (ADNOC Offshore) | Zahaf, Kamel (ADNOC Offshore) | Ibrahim, Loay (ADNOC Offshore) | Liu, Yaxin (ADNOC Offshore) | Darous, Christophe (Schlumberger Oil Company) | Barillas, Luisa (Schlumberger Oil Company)
Reservoir Rock Typing and saturation modeling need a two-sided methodology. One side is the geological side of the rock types to populate properties within geological concepts. The other side is addressing reservoir flow and dynamic initialization with capillary pressure. The difficulty is to comply with both aspects especially in carbonates reservoirs with complex diagenesis and migration history. The objective of this paper is to describe the methodology and the results obtained in a complex carbonate reservoir.
The approach is initiated from the sedimentological description from cores and complemented with microfacies from thin sections. The core-based rock types use the dominant rock fabrics, as well as the cementation and dissolution diagenetic processes. The groups are limited to similar pore throat size distribution and porosity-permeability relationships to stay compatible with property modeling at a later stage.
At log-scale, the rock typing has a focus on the estimation of permeability using the most appropriate logs available in all wells. Those logs are porosity, mineral volumes, normalized saturation in invaded zone (Sxo), macro-porosity from borehole image or Nuclear Magnetic Resonance (NMR), NMR T2 log mean relaxation, and rigidity from sonic logs. A specific calculation to identify the presence of tar is also included to assess the permeability better and further interpret the saturation history. The MICP data defined the saturation height functions, according to the modality of the pore throat size. The log derived saturation, and the SHFs are used to identify Free Water Level (FWL) positions and interpret the migration history.
The rock typing classification is well connected with the geological aspects of the reservoirs since it originates from the sedimentological description and the diagenetic processes. We identified a total of 21 rock types across all the formations of interest. We associated rock types with depositional environments ranging from supra-tidal to open marine that controls both the original rock fabrics and the diagenetic processes. The rock typing classification is also appropriate to model permeability and saturation since core petrophysical measurements were in use during the classification. The permeability estimation from logs uses multivariate regressions that have proven to be sensitive to permeability after a Principal Component Analysis per zones and per lithologies. The difference between the core permeability and the permeability derived from logs stays within one-fold of standard deviation as compared to the initial 3-fold range of porosity-permeability. We assigned the rock types with three Saturation Height Function (SHF) classes; (unimodal-dolomite, unimodal- limestone & Multimodal-Limestone). The log derived water saturation (Sw) from logs and SHF shows acceptable agreement.
The reservoir rock typing and saturation modeling methodology described in this paper are considerate of honoring geological features and petrophysical properties to solve for complex diagenesis and post-migration fluid alteration and movement processes.
Al-Azmi, Mejbel Saad (Kuwait Oil Company) | Al-Otaibi, Fahad (Kuwait Oil Company) | Kumar, Joshi Girija (Kuwait Oil Company) | Tiwary, Devendra (Kuwait Oil Company) | Al-Ashwak, Samar (Kuwait Oil Company) | Dzhaykiev, Bekdaulet (Baker Hughes, a GE Company) | Shinde, Neha (Baker Hughes, a GE Company) | Hardman, Douglas (Baker Hughes, a GE Company) | Noueihed, Rabih (Baker Hughes, a GE Company) | Gadkari, Shreerang (Baker Hughes, a GE Company)
The complex nature of the reservoir dictated comprehensive formation evaluation logging that was typically done on wireline. The high angle designed for maximum reservoir exposure, high temperature, high pressure (HTHP), differential reservoir pressure and wellbore stability challenges necessitated a new approach to overall formation evaluation. The paper outlines Formation Evaluation strategy that reduced risk, increased efficiency and saved money, while ensuring high quality data collection, integration and interpretation.
After review of all risks, a decision to utilize Managed Pressure Drilling (MPD) for wellbore stability, Logging While Drilling (LWD) to replace wireline and Advanced Mudlogging Services was implemented. The Formation Evaluation team utilized LWD resistivity, neutron, density and nuclear magnetic resonance logs supplemented with x-ray diffraction (XRD), x-ray fluorescence (XRF) and advanced mud gas analysis to ensure comprehensive analysis. The paper outlines workflows and procedures necessary to ensure all data from LWD, XRF, XRD and mud gas are integrated properly for the analysis.
Effects of Managed Pressure Drilling on mud gas interpretation as well as cuttings and mud gas depth matching are addressed. Depth matching of all data, mud gasses, cuttings and logs are critical for detailed and accurate analysis and techniques are discussed that ensure consistent results. Complex mineralogy due to digenesis and effect of LWD logs are evident and only reconciled by detailed XRF and XRD data. The effects of some conductive mineralogy are so dramatic as to infer tool function compromise. The ability to determine acceptable tool response from tool failures eliminates unnecessary trips and leads to efficient operations. The final result of the above data collection, QC and processing resulted in a comprehensive formation evaluation interpretation of high confidence.
Finally, conclusions and recommendations are summarized to provide guidelines in Formation Evaluation in similar challenging highly deviated, HTHP, complex reservoir environments on land and offshore.
Full field development of the Upper Jurassic carbonates, offshore Abu Dhabi is exceedingly challenging. The heterogeneous texture, complicated pore systems and intensive lithology changes all mark the regressive cycles of sedimentation. Such complicated characteristics obscure formation evaluation of these formations. Advanced well logging tools and interpretation methodologies are implemented to minimize the petrophysical uncertainties to qualify the products as field development critical elements. This case study highlights a newly applied NMR log interpretation approach. The results help to understand the complex pore system in a tight carbonate layer, along a horizontal drain drilled close to the oil-water contact.
NMR log data was acquired in real-time while drilling simultaneously with Gamma Ray, Resistivity and Image Logs. Earlier field studies recommended swapping standard T2 free fluid relaxation cutoff values by actual laboratory NMR measurements for a higher precision suitable for the reservoir texture heterogeneity, the study itself supported the application of higher cutoff values to better discriminate the free fluid in well-connected macro pores from the irreducible which will have a direct impact on the computed permeability.
In this case study, a variable free-fluid T2 cutoff was firstly implemented based on arbitrary estimations to match the computed Coates permeability to the offset core values. Free-fluid, irreducible fluids were sequentially computed. A unique NMR-Gamma Inversion (NMR-GI) workflow is further utilized as a mathematically defined approach to process the raw data using probabilistic functions. The result is a more precise pore size distribution, coherent with the geological variations. NMR Capillary pressure was computed.
The complex formation texture could be accurately tracked for thousands of feet drilled along the horizontal drain. After validation with offset core, the NMR-GI interpretation was combined with, Archie saturation and Image log analysis for a conclusive assessment. Hydraulic flow units were combined. Successful completion design and production zone selection articulated on the defined open hole log interpretation.
NMR while drilling logging and the applied (NMR-GI) methodology prove to be leading tools to assist in resolving carbonate reservoir complexities. Not only that they help to understand the pore system characteristics, but they effectively support well placement, completion and production.
BinAbadat, Ebtesam (ADNOC Offshore) | Bu-Hindi, Hani (ADNOC Offshore) | Lehmann, Christoph (ADNOC Offshore) | Kumar, Atul (ADNOC Offshore) | AL-Harbi, Haifa (ADNOC Offshore) | AL-Ali, Ahmed (ADNOC Offshore) | Al Katheeri, Adel (ADNOC Offshore)
In this study, core and log data were integrated to identify intervals which are rich in stromatoporoids in an Upper Jurassic carbonate reservoir of an offshore green field Abu Dhabi. The main objective of this study was to recognize and stromatoporoids floatstones/rudstones in core, and develop criteria and workflow to identify them in uncored wells using borehole images.
The following workflow was used during this study: i) Identification of the stromatoporoid feature in pilot wells with core and borehole images, ii) Investigate the properties and architecture of stromatoporoid bodies, iii) Integrate the same scale of core observations with borehole images and conventional log data (gamma ray, neutron porosity and bulk density logs) to identify stromatoporoid-rich layers, iv) Performing a blind test on a well by using the criteria developed from previous steps to identify "stromatoporoid accumulations" on a borehole image, and validate it with core observations.
In the reservoir under investgation, stromatoporoid floatstones/rudstones intervals were identified and recognized both on core and borehole image in the pilot wells. These distinct reservoir bodies of stromatoporoids commonly occur in upper part of the reservoir and can reach to a thickness of around 20ft. The distribution and thickness of stromatoporoid bodies as well as growth forms (massive versus branching) were recognized on core and borehole images. The accumulations varied between massive beds of containing large pieces of stromatoporoids and grainstone beds rich in stromatoporoid debris. The massive beds of stromatoporoid accumulations are well developed in the northern part of the field. These layers can enhance the reservoir quality because of their distinct vuggy porosity and permeability that can reach up to several hundred of milidarcies (mD). Therefore, it is important to capture stromatoporoid layers both vertically and laterally in the static and dynamic model. Integrating borehole image data with core data and developing a workflow to identify stromatoporoid intervals in uncored wells is crucial to our subsurface understanding and will help to understand reservoir performance.
Integration of image log data which is calibrated to core and log data proved to be critical in generating reservoir facies maps and correlations, which were integrated into a sequence stratigraphic framework as well. The results were used in the static model in distribution of high permeability layers related to the distribution of stromatoporoids.
Al-Zaabi, Fatema (ADNOC Offshore) | Amer, Mohamed (ADNOC Offshore) | Al-Jaberi, Salem (ADNOC Offshore) | Afzal, Nusrat (ADNOC Offshore) | Abdelbagi, Mohamed (ADNOC Offshore) | Deng, Lichuan (Baker Hughes, a GE Company) | Soliman, Ahmed (Baker Hughes, a GE Company) | Kieduppatum, Piyanuch (Baker Hughes, a GE Company) | Bhatt, Pranjal (Baker Hughes, a GE Company) | Fernandes, Warren (Baker Hughes, a GE Company)
Reservoir A is an Upper Jurassic reservoir in offshore Abu Dhabi, composing layers of dense anhydrite and porous mixed lithology of dolomite and limestone. Petrophysical study from multiple wells suggests that the rock quality within the reservoir has significant lateral and vertical variations that can result in different flow capacities. Consequently, it is crucial to identify the rock quality variations and the consequent flow capacity in horizontal wells to optimize development plan, ideally in real-time. However, these lateral and vertical variations are not visible from conventional porosity (density / neutron) logs, making identification of rock quality very challenging. This paper introduces an innovative magnetic resonance (NMR)-based real-time method of permeability prediction and rock typing.
Wireline logs including NMR were acquired in a pilot well, providing porosity and extensive T2-based information (permeability index, irreducible and movable fluid volume and porosity partition). Routine core analysis was also available to calibrate the NMR data, achieving a suitable correlation for NMR permeability index calibration in this field. Several rock types could be identified with the Windland R35 technique using porosity and calibrated permeability from NMR. This identification was then validated by rock types from cores. The application of knowledge gained from the study led to advanced reservoir characterization solely based on the NMR log. The process was applied to high-angle and horizontal (HAHZ) wells where the NMR full-spectrum log while drilling was available.
Several slanted wells were drilled with a fit-for-purpose logging-while-drilling (LWD) suite including NMR for geo-steering and formation evaluation. The real-time LWD NMR data helped trace a remarkable change of irreducible water level through certain layers, suggesting that the subzones of Reservoir A changed pore geometry and rock type laterally, resulting in variations of flow capacity and reservoir performance.
In one example, this method indicated unexpected good rock quality in one of these subzones considering the experience from offset well. Subsequently, the LWD formation-testing tool confirmed the result with mobility measurements, proving the NMR-based methodology was valid.
This process normally applies to memory data after drilling, playing a key role in designing completion strategy in a timely manner. The process is also available in real-time while drilling if full NMR data is transmitted to surface, serving as a safer logging-tool for identification of sub-zones with additional valuable information compared to regular porosity tools with chemical radioactive source.