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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.
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.
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.
Serry, Amr (ADNOC Offshore) | Al-Hassani, Sultan (ADNOC Offshore) | Budebes, Sultan (ADNOC Offshore) | AbouJmeih, Hassan (ADNOC Offshore) | Kaouche, Salim (ADNOC Offshore) | Aki, Ahmet (Halliburton) | Vican, Kresimir (Halliburton) | Essam, Ramy (Halliburton) | Lee, Jonathan (Halliburton)
This case study demonstrates the role of nuclear magnetic resonance (NMR) T1 spectra, as used to drill complex undeveloped carbonate formations offshore Abu Dhabi. The scope of this project exceeds the traditional porosity-permeability approach to exploit the wealth of information about the rock texture, pore size distribution, flow units and a new methodology of NMR T1 data processing.
Evaluation of pore size distributions based on T1 vs. T2 spectra is addressed in two case study wells; one using a 6 ¾-in., and the other a 4 ¾-in. mandrel size for the first time in UAE. Finally, other log-derived permeabilities are presented, together with high-resolution microresistivity image interpretation and production log results in an integrated approach for improved understanding of the petrophysical character of these undeveloped units.
NMR T1 measurements are utilized for the first time in the lateral sections as part of a bottomhole assembly (BHA) consisting of a rotary steerable system (RSS), and logging-while-drilling (LWD) sensors, including high-resolution microresistivity imaging, laterolog and azimuthal electromagnetic wave resistivities, thermal neutron porosity, azimuthal density, azimuthal multipole acoustic, ultrasonic caliper and near-bit azimuthal gamma ray. During NMR T1 measurements, the spin relaxation time carries information about the liquid-solid surface relaxation and bulk-fluid relaxation, hence, it is neither affected by rock internal magnetic field gradients nor by differences in fluid diffusivity. Also, T1 logging measurements are influenced by instrument artefacts to a much lesser extent than T2 results, having several advantages over T2, especially regarding polarization and tool motion while drilling.
The real-time availability of NMR sourceless porosity measurements significantly improved drilling decisions to place the two case history wells into favourable zones and NMR T1 permeabilities were derived together with acoustic and high-resolution microresistivity image-based permeabilities which were then correlated to production logs.
The results indicate that T1 measurements are an effective, practical solution for rock quality evaluation using LWD real-time datasets free from BHA motion and fluid diffusion effects. Comparisons of T1 and T2 logs show that T1 yields equivalent formation evaluation answers, despite its sparser nature.
The T1 spectra facilitated improved pore size distribution, permeability estimation and marking of the hydraulic flow units in the heterogeneous, undeveloped Upper Jurassic reservoir units, paving the way for the consideration of T1 logging as a viable, and in some cases superior alternative to T2 logging. This paper presents the multidisciplinary approach used to benchmark and optimize the future field development program.
Kumar Mishra, Anoop (ADNOC Offshore) | Anurag, Atul (ADNOC Offshore) | Al Balooshi, Mohammed (ADNOC Offshore) | Javid, Khalid (ADNOC Offshore) | Sinha, Rakesh (ADNOC Offshore) | Al-Hashmy, Ghassan (ADNOC Offshore) | Hosany, Khalil (ADNOC Offshore) | Mills, Carey (ADNOC Upstream) | Basioni, Mahmoud (ADNOC Upstream) | Al-Blooshi, Abdulla (ADNOC Upstream) | Aryani, Fatima (ADNOC Upstream) | Mandl, Johannes (ADNOC Upstream) | Dasgupta, Suvodip (Schlumberger) | Raina, Ishan (Schlumberger) | Ali, Humair (Schlumberger) | Uruzula Abdulrahim, Jaja (Schlumberger) | Al-Afeefi, Baraka (Schlumberger) | Hollaender, Florian (Schlumberger)
Recent appraisal drilling undertaken by ADNOC in offshore Abu Dhabi has focussed on evaluation of the Middle Jurassic to Permian Deep Gas reservoir sequences. These formations are characterised by low porosity and permeability and typically contain either dry gas or gas condensate fluids. These appraisal activities form part of a larger program leading to development of these resources. Principal uncertainties addressed by appraisal drilling include determining fluid characteristics, reservoir properties and ultimately well deliverability. This paper uses one such recently drilled (typical) appraisal well as an example of the workflow employed.
Exploration drilling of the Middle Jurassic to Permian reservoirs in this field dates back to 1984 and utilised available logging tools and techniques of the time. The current appraisal drilling program built on the results of this work and utilizes the latest available technology and interpretation techniques to both quantify reservoir and fluid properties and minimise subsurface development uncertainties. Typical data acquisition programs includes: conventional coring, advanced mud log data acquisition, triple-combo wireline data, borehole image data, elemental spectroscopy, azimuthal dipole sonic data and formation pressure measurements/samples. The formation evaluation program involved careful analysis and integration of this data to decide at first on formation sampling points and then subsequently testing zones. This approach necessitated the involvement of multiple stakeholders (end-users as well as people performing the interpretation) and required close communication to facilitate rapid, informed, decision making at key stages of the project execution.
These different types of data become available at differing times during the course of drilling a well with the earlier acquired data informing the decision-making process on subsequent data acquisition. The first data to come in were the "mud logs" which includes drilling parameters (such as Rate of Penetration) and gas chromatography. This data provides an initial indication of potential zones of interest, along with fluid type. Following acquisition of wireline data, a "quicklook" formation evaluation was integrated with earlier geological analysis to determine the formation pressure and fluid sampling points.
Combined together, these results formed the basis of an integrated reservoir and saturating fluid interpretation leading to the selection of perforation intervals for well testing. Effective implementation of this work flow requires a collaborative approach combined with ongoing data integration. This process of consultation across multiple subsurface disciplines and stepwise evaluation guiding future data acquisition requires a certain degree of evaluation flexibility but ultimately results in better decisions.
The philosophy of integrating multiple data sources and disciplines in a collaborative evaluation and decision-making work flow is an essential enabler for the exploitation of the Deep Gas resource in Abu Dhabi.
In the example well, test results are in accord with the log interpretation work and provide a path forward towards field development and gas production.
Franquet, Javier Alejandro (Baker Hughes, a GE company) | Singh, Rudra Pratap Narayan (ADNOC offshore) | Diaz, Nerwing (Baker Hughes, a GE company) | Anurag, Atul (ADNOC offshore) | Balooshi, Mohamed Ali Al (ADNOC offshore) | Jefri, Ghassan Al (ADNOC offshore) | Hosany, Khalid Ibrahim M (ADNOC offshore) | Cesetti, Mauricio (ADNOC offshore) | Kindi, Rashid Khudaim Al (ADNOC offshore) | Zhunussova, Gulzira (Baker Hughes, a GE company) | Bradley, Tom (Baker Hughes, a GE company) | Kirby, Cliff (Baker Hughes, a GE company)
An injector well drilled from an artificial island in UAE left a non-magnetic fish during well control operations across lower Cretaceous reservoirs below the 9-5/8-in. casing shoe, exposing all upper Jurassic reservoirs flow units. The situation was a serious concern to field developing and reservoir integrity as aquifer, gas and many layers of oil reservoirs were connected through the borehole below the fish. It was decided to sidetrack around the fish to intersect the original 8½-in. open-hole section. The sidetrack was accomplished, but the first attempt to intersect the mother hole was unsuccessful. Therefore, an innovative solution was needed for detecting the mother hole to intersect it.
A combination of cross-dipole deep shear acoustic, high-resolution induction and orientation wireline measurements were advised. These measurements would be used to update the wellbore survey and to detect acoustic reflections from the mother hole for identifying its relative orientation with respect to the sidetrack hole. Detailed measurement-while-drilling (MWD) wellbore survey analyses were conducted for the original and sidetrack holes beside typical corrections, such as Sag and drillstring interference. The deep shear wave imaging data recorded in the side-track hole was processed at multiple X-dipole polarization directions to detect shear reflection from the mother-hole and back calculate its relative position.
The high-resolution induction data could not detect the fish from the sidetrack, but few dipole reflections of the mother hole were detected in two locations. The orientation of the reflectors was consistent with the revised wellbore survey analysis, and this information was used to make the directional drilling corrections required to intersect the mother hole. The use of deep shear wave imaging data to identify a nearby open hole was a non-conventional application of this technology, but it definitely facilitated directional drilling operations to successfully intersect a mother hole that cannot be left uncompleted. After the openhole intersection, a good borehole condition was encountered due to the non-damaging fluid system, allowing the well to be completed as per original plan. Achieving this challenging directional drilling objective was critical for the field development plan of these offshore UAE reservoirs.
This case study represents the first documented field experience of using deep shear wave imaging data in the petroleum industry for assisting directional drillers to intersect an open hole mother wellbore after sidetracking a fish.
Anurag, A. K. (Abu Dhabi Marine Operating Company) | Mishra, A. K. (Abu Dhabi Marine Operating Company) | BinAbadat, E. K. (Abu Dhabi Marine Operating Company) | Hosany, K. I. (Abu Dhabi Marine Operating Company) | Al Hashmi, G. (Abu Dhabi Marine Operating Company) | Al-Harbi, H. (Abu Dhabi Marine Operating Company) | Brindle, F. R. (Abu Dhabi Marine Operating Company) | Kuliyev, M. (Abu Dhabi Marine Operating Company) | Gzara, K. (Schlumberger)
Pore network complexity in carbonate reservoirs is the result of heterogeneous pore size distributions, diagenesis and fractures. Fluid movement through such reservoirs is difficult to model, and permeability depends on the scale considered. Existing permeability computations are empirical in nature, and simply estimate average permeability curves that are hard to upscale. A novel approach for azimuthal and dynamic permeability estimation that preserves formation heterogeneity information is presented through a case study of Jurassic carbonate reservoirs.
First, existing petrophysical procedures are extended to take advantage of most Logging-While-Drilling (LWD) data being available in azimuthal fashion as images, to produce azimuthal lithology, porosity and fluid saturation images that retain all the information present in the original LWD images, instead of average results. A new azimuthal permeability image, derived from invasion dynamics, complements the volumetric petrophysical analysis. In general, while drilling, mud filtrate volume is highly correlated to formation permeability, time after bit (
LWD data from several horizontal wells were processed and the benefits of displaying the resulting volumetric petrophysical analysis images in 3D are discussed. The processed resistivity images confirm heterogeneous /complex formation texture, with thin layering (~
During drilling, openhole logs provide valuable data to identify the location of hydrocarbon resources, characterize the host formation, and quantify the asset in terms of size and producibility. Such data acquisition during field appraisal plays a critical part in the preparation of the field development plan. However, openhole logs may not be available or may not be possible due to various constraints. In some cases, data that is essential for petrophysical evaluation has been overlooked during the planning of the openhole log acquisition. In other cases, wellbore conditions while drilling may preclude openhole logging in favor of securing the well. This latter scenario can often occur in appraisal wells when knowledge of the pressure regimes in the different formations in the field is still incomplete.
Several logging services are available for acquiring formation information through casing. This capability can provide an excellent option to acquire the necessary formation evaluation data through casing, thereby completing the input to the decision-making process.
We present three separate examples in which casedhole formation evaluation was used to augment data acquired in the open hole for an improved formation evaluation. The applications range from providing reliable density and sonic data for seismic tie-in to providing more accurate estimates of porosity and saturation for selection of test intervals or for input to the static geological model. The examples demonstrate the use of various through-casing formation evaluation technologies including density, neutron, resistivity, acoustic compressional and shear slowness, and pulsed neutron capture and inelastic spectroscopy logs. We show that through a judicious combination of logs the primary evaluation objectives can be fulfilled.
We discuss the challenges in data acquisition, the steps for quality assessment of the data acquired through casing, and interpretation procedures to integrate all the data in an answer product. The substantial benefit of such an option to the operator is also discussed.