Patacchini, Leonardo (Abu Dhabi Marine Operating Company) | Mohmed, Farzeen (Abu Dhabi Marine Operating Company) | Lavenu, Arthur P. C. (Abu Dhabi Marine Operating Company) | Ouzzane, Djamel (Abu Dhabi Marine Operating Company) | Hinkley, Richard (Halliburton) | Crockett, Steven (Halliburton) | Bedewi, Mahmoud (Halliburton)
The classic method for initializing reservoir simulation models in the presence of a transition zone, based on primary drainage capillary-gravity equilibrium, is extended to account for partial reimbibition post oil migration. This tackles situations where structural events, such as trap tilting or caprock leakage, caused the current free-water level (FWL) to rise above deeper paleo-contacts. A preliminary primary drainage initialization is performed with zero capillary pressure at the paleo (or deepest historical) FWL, to obtain a minimum historical water saturation distribution. From a capillary pressure hysteresis model, it is then possible to determine the appropriate imbibition scanning curve for each gridblock, which are used to perform a second initialization with zero capillary pressure at the current FWL. With the proposed method, log-derived saturation profiles can be honored using a physically meaningful capillary pressure model. Furthermore, when relative permeability hysteresis is active, it is possible as a byproduct of the initialization to assign the correct scanning curves at time zero to each gridblock, which ensures that initial phase mobilities (hence reservoir productivity) and residual oil saturation (hence recoverable oil to waterflood) are modeled correctly. This is demonstrated with a synthetic vertical 1D model. The method was implemented in a commercial reservoir simulator to support modeling work for a giant undeveloped carbonate reservoir, where available data suggest that more than 3/4 of the initial oil in place could be located between the current FWL and a dome-shaped paleo-FWL. This work is used as a case study to illustrate the elegance of the proposed method in the presence of multiple (or tilted) paleo-FWLs, as only one set of capillary pressure curves per dynamic rock-type is required to honor the complex logderived saturation distribution.
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 (~
Al-Balooshi, M. (Abu Dhabi Marine Operating Company) | Anurag, A. K. (Abu Dhabi Marine Operating Company) | Mishra, A. K. (Abu Dhabi Marine Operating Company) | Al-Ali, A. E. (Abu Dhabi Marine Operating Company) | Hosany, K. I. (Abu Dhabi Marine Operating Company) | Al-Jefri, G. M. (Abu Dhabi Marine Operating Company) | Sinha, R. (Abu Dhabi Marine Operating Company) | Maeso, C. J. (Schlumberger) | Girinathan, S. (Schlumberger) | Legendre, F. (Schlumberger) | Gzara, K. (Schlumberger)
Borehole images constitute a rich source of high-resolution geological data about various formations penetrated by oil and gas wells. Interpretation techniques of these images have progressively improved over the years and provide detailed information about formation dips, structure, rock fabric, fractures, and drilling-induced borehole damage. Wireline tools have the flexibility to be used in a wide variety of borehole sizes. In contrast, logging-while-drilling(LWD) tools are designed for particular borehole sizes. A new high-resolution LWD imaging tool has been built for 8.5-in. boreholes. This paper presents the results from two logging runs located in offshore United Arab Emiratescarbonate fields, including the first worldwide logging run of the tool.
Measurements made by this new high-resolution imaging tool are based on laterolog principles for the measurement of resistivity. The tool performs two main types of measurements, including an array of focused resistivity measurements with an axial resolution near 1 in., and an ultrahigh-resolution resistivity imaging pad consisting of an array of eight buttons. This paper focuses on the LWD tool’s imaging section, designed to provide the same volume ofinvestigation as one of the focused resistivity measurements. This design featureresults in measurement calibration confidence with respect to the formation resistivity, allowing for quantifiable analysis of the formation properties using the image data. The data for this first run were acquired during a washdown through a carbonate-evaporite sequence. Borehole deviation was approximately 60° and the mud was a typical high-salinity water-base mud. A suite of wireline data, acquired after the LWD washdown run, includes a pad-based resistivity imaging tool, which allows comparison of thetwo sets of acquired data.
Data from both the wireline and new high-resolution imaging LWD tools were processed and interpreted. Structural and cross-bedded layers were clearly visible on both imaging-type tools. Borehole crossing and layer-bound fractures were also observed and could be quantified from both tools.
Examples show how identifying some featuresis made easier on the full borehole coverage of the LWD images; however, the higher resolution of the wireline tool is beneficial for identifying some textural features. Results from both types of logging tools are presented and the similarities and differences are summarized. Advances in borehole image visualization are also presented as 3D views in addition to cross-sectional views across the borehole, which make visualization of features more user friendly for those not familiar with borehole image interpretation.
Gazi, Islam (Abu Dhabi Marine Operating Company) | Al-Ali, Hassan Ahmed (Abu Dhabi Marine Operating Company) | Al-Falahi, Ahmed (Abu Dhabi Marine Operating Company) | Al-Shamsi, Mohammad Hassan (Abu Dhabi Marine Operating Company) | Khanbooli, Mohamed (Abu Dhabi Marine Operating Company)
Currently, Abu Dhabi Marine Operating Company (ADMA-OPCO) is developing three new fields. The respective projects or fields are named as A, B, C in subsequent sections of this paper. All three new fields have Main Automation Contractor (MAC) concept which means plant process control and safety systems are supplied by single manufacturer. This paper presents the difference in MAC concept between these projects and proposes an extended MAC Scheme which covers the electrical control system also in MAC scope. The authors predict that merger of process and electrical control system along with most of the subsystems (Packages) into a unified network will be the trend for future green field projects. The paper describes the technical and commercial advantages the proposed scheme can have over conventional MAC philosophy. A section of the paper also highlights the challenges associated for implementation of the proposed architecture.
The field considered in this paper is located in offshore Abu Dhabi with a production history of nearly fifty years. The long term field development plan includes completing hundreds of wells with intelligent completion. A pilot smart well targeting three separate flow units was introduced in 2014 before full-field scale application. One of the challenges faced while piloting the smart well is zonal production allocation which will be addressed in this paper.
Best practices worldwide to monitor and allocate stacked production in smart wells include: periodic PLTs, permanent downhole Venturi flowmeters, rate calculation using pressure loss across the ICV, IPR curve based allocation, DTS optical fiber, geochemical fingerprint analysis and downhole acoustic passive listening. In this paper PLT based approach, ICV pressure loss and IPR-based allocation methods are tested and compared based on three years pilot well production history, numerous flow tests and five downhole gauges recordings.
Though PLT based approach is the easiest method to apply on brownfields it has the biggest uncertainties due to following factors: PLTs are not logged for full range of possible ICV positions; PLTs in horizontal wells are rarely logged in well-stabilized regime; coiled tubing in deviated wells have a direct impact on the inflow proportion. Pressure loss across ICV method based on multirate flow test results look promising but absolutely requires at least partial choking of all ICVs. The biggest advantage of dP vs ICV method is non-sensitivity to transitory flow behavior. IPR curve based method found to be simple to implement as well as quite robust for certain conditions. Main drawback of IPR method is its non-reliability in transition period if ICV / Wellhead Choke positions are modified.
A new allocation methodology is proposed and tested in this paper – production allocation using numerical simulation. If properly applied, this methodology can overcome the transition period issue of IPR method. The biggest advantage of this method is that it may be the most accurate method for back-allocation even though it is very time consuming to implement. Another novel method proposed in this paper is using dual downhole gauges per ICV. Zonal allocation is computed considering friction pressure loss between ICVs. This method is successfully tested and validated in a recent water injector with ICVs. It can fit best for single phase fluid and relatively high production / injection rates.
Maalouf, Christophe Bassem (Abu Dhabi Marine Operating Company) | Zidan, Maher (Abu Dhabi Marine Operating Company) | Uijttenhout, Mattheus (Abu Dhabi Marine Operating Company) | Hernandez, Eglier Jose (Abu Dhabi Marine Operating Company) | Al-Jaberi, Salem (Abu Dhabi Marine Operating Company) | Saeed, Yawar (Schlumberger) | Gambier, Philippe (Schlumberger) | Gil, Adelis Alfonzo Valero (Schlumberger) | Graham, Robert A. (Schlumberger)
Inflow Control Devices (ICDs) are typically deployed as parts of the lower well completion in horizontal wells to equalize the pressure drop along the drain length and to achieve a uniform flow through the formation. Therefore, ICDs can delay undesired water or gas breakthroughs and maximize the reservoir recovery, particularly when producing from heterogeneous reservoirs. However, by imposing additional pressure drops across segments, ICDs can reduce the production potential in the early stages of well life. This paper presents a novel design methodology, using dynamic reservoir modeling, to make ICDs responsive to the well flowing conditions and to eliminate the pressure drops across segments in early well life by using the shifting technique.
The reservoir contains several sublayers and exhibits significant contrast in rock and fluid properties. The horizontal oil producer targets all sublayers simultaneously. A five-spot water injection pattern is planned to maintain the reservoir pressure. Usually, ICDs are designed based on well models that do not cover the entire expected well life. In our methodology, we rely on the dynamic reservoir model to predict changes of pressure and fluids along the drain and to find the optimal ICDs design that can respond to these changes. Sliding sleeves are combined with ICDs to allow choking back unwanted water production over time. Moreover, the design is tested with a systematic sensitivities approach for different well and reservoir conditions to ensure a robust design against reservoir uncertainties. The proposed completion design methodology was successfully implemented in a horizontal well crossing a layer-cake heterogeneous carbonates reservoir in offshore Abu Dhabi.
The well deliverability analysis suggests that the well cannot produce more than 25% water cut without artificial lift. Sensitivities were conducted at varying water cuts for each ICD compartment in addition to specific sensitivities for the high permeability compartments. To reach the optimal completion design, reservoir simulations were used to evaluate the benefits of various combinations of ICDs and nozzles sizes and their overall impact on well performance. The optimal design consisted of five compartments in the horizontal section with 14 ICDs and proved to be more effective in delaying water breakthrough into the compartments with high permeability without affecting the initial production rates.
The benefits of ICDs are well known in the industry to equalize the well flux based on permeability contrast by choking production selectively. The novel technique presented in this paper eliminates the choking effect on proction during the early well life while retaining the full benefits of ICDs for later stages; using the shifting technique, the offending layers can be choked back or closed completely to maximize oil production rates and reserves.
Hou, Lian (Abu Dhabi Marine Operating Company) | Lavenu, Arthur P. C. (Abu Dhabi Marine Operating Company) | Xi, GuiFen (Abu Dhabi Marine Operating Company) | Al-Kaabi, Ahmed Saeed (Abu Dhabi Marine Operating Company) | Van Kleef, Franciscus (Abu Dhabi Marine Operating Company) | Lecoq, Thierry Francis (Abu Dhabi Marine Operating Company) | Al Blooshi, Asma Mohamed (Abu Dhabi Marine Operating Company)
Faults and fractures play an important role in reservoir production, since they can act either as barriers or conduits for fluid migration. They are also one of the key factors to be considered for drilling trajectory design. However, it is very challenging to delineate fractures due to the limitation of seismic resolution. The objective of this study was to conduct fracture cluster characterization for one of the carbonate reservoirs in Abu Dhabi, using a recently acquired 3D seismic survey.
In this study, the similar workflow used by
In addition, previously the discontinuities along NNE-SSW direction in the area of interest were considered as seismic acquisition footprints. Through this study, it was proved that those discontinuities are small scale faults, hereby enhanced the existing reservoir characterization.
The findings on faults and fractures characterization in the study area are critical in field development plan and drilling efficiency. This study showed that integrating data from different disciplines is a reliable and effective way to delineate fracture clusters.
Maalouf, Christophe Bassem (Abu Dhabi Marine Operating Company) | Hernandez, Hernandez Jose (Abu Dhabi Marine Operating Company) | Zidan, Maher (Abu Dhabi Marine Operating Company) | Uijttenhout, Mattheus (Abu Dhabi Marine Operating Company) | Al-Jaberi, Salem (Abu Dhabi Marine Operating Company)
After a long history of unsuccessful appraisal wells, a new phase of reservoir appraisal focusing on data gathering for reservoir and fluid characterization led to positive results. Fluid sampling, acid recipe, formation pressure, and horizontal drilling were key factors for the successful appraisal. This reservoir is now a significant upside for the field development plan.
During the early phase of field development, careful data gathering plan was designed to characterize the reservoir. The plan included coring, logging, reservoir formation pressure, downhole fluid analysis, fluid sampling, conventional Pressure, Volume, and Temperature (PVT) studies, and asphaltene and flow assurance studies. After collecting downhole oil samples, a compatibility study with acid recipe was performed and many chemical additives were tested to find the optimal one. A horizontal drain was drilled to maximize the reservoir contact. The well was tested with drill stem test (DST).
Reservoir formation pressure acquired in 4 pilot holes at locations covering the reservoir confirmed fluid mobility, initial reservoir pressure, and possible oil pool limits. Downhole fluid analysis and sampling allowed the characterization of the reservoir fluid properties. Conventional PVT, asphaltene and flow assurance studies confirmed light oil with good flow potential. However, the compatibility study with existing acid recipe showed a high increase in fluid viscosity. This could prevent the well from flowing after matrix acidization. Naphta, among many tested chemical additives, proved to be the best to resolve the viscosity increase. The horizontal drain was successfully acidized with the new acid recipe and the well flowed oil during DST for the first time, 46 years after the field discovery. The well was tested through separator at different chokes before the main pressure build-up (PBU). The well was shut-in for 78 hours. BU analysis showed that reservoir permeability is in line with previously collected cores.
Although earlier appraisals were successful in upper reservoirs, a classic approach to reservoir appraisal of this thin oil reservoir failed. Our approach of carefully planning the data gathering sequence, testing acid and oil compatibility, proved essential to understand the past failures, correct the shortcomings, and carry on a successful appraisal.
Short-term production and injection optimization are best approached from an integrated surface/subsurface perspective, recognizing that well performance is driven by competition for an existing network hydraulic capacity.
This paper presents a tool for real-time optimization (RTO) of water-injection systems at the scheduling time scale (i.e., days to months). Its development stemmed from the observation that operations such as pigging or shutting manifolds for rig activity might disrupt the injection network balance; hence, injectors would benefit from quick control readjustments. Furthermore, an existing network is not necessarily able to distribute available water where desired, and control compromises best found by an optimizer should be sought.
It is assumed that reservoir conditions are stationary, and injection targets at any level of granularity (well, reservoir segment, or field level) have been established based on subsurface requirements. By use of performance curves for each injector and either a simplified or a full-fledged network model, the algorithm finds a set of optimal well controls with a steepest-descent method implemented in Microsoft (2016) Visual Basic for Applications (VBA). The interface is spreadsheet-based, facilitating updates in well-performance data or changes in reservoir requirements. When needed by the algorithm, a third-party hydraulic-flow simulator able to balance the system from the injection modules down to the manifolds is called through an application programming interface.
A case study is presented, illustrating how the tool has been used to estimate the benefits of installing wellhead chokes on the currently more than 200 active injection strings of a giant oil field offshore Abu Dhabi.
In a giant carbonate reservoir, located offshore Abu Dhabi, permeability and production data are hard to reconciliate. Recent investigations on this reservoir have shown that it is affected by natural fractures. Borehole images, cores and thin-sections allowed characterizing two main fracture sets. However, the scarcity of data, with regards to the size of the reservoir, did not allow building a discrete fracture network. To overcome this gap, modelling fractures in an implicit way appears the best and simplest solution to enhance permeability and match the production data.
Implicit means that fractures are not considered as a discrete object. Instead, at the cell scale, fracture impact on permeability has been translated into multipliers in the x, y, and z directions, superimposed on the matrix permeability. The process of implicit fracture modelling is not straightforward. Building a fracture conceptual model (seismic faults, fault-related fractures, subseismic faults, and background fractures) is the starting point, to understand the big picture. The second step is defining the layer/fracture relationships, and quantifying the interaction between matrix and fractures (transmissibility). The third step is modelling and implementing the permeability modifiers in the 3D geological grid.
The distribution and occurrence of the different features remains difficult to constrain using one single deterministic model. Using multi-realization is powerful tool to get the closest match to PTA.
Deterministic scenarios have been created combining joints and faults, assigning different properties to each of the feature: size, frequency, degree of baffling, degree of permeability anisotropy, vertical transmissibility, mechanical stratigraphy, position to the structure of the reservoir…The permeability field resulting from each scenario has then be compared to PTA to determine which case best matches the dynamic data. The created permeability array is then added to the matrix permeability of the reservoir, enhancing it up to 6 times.
Implicitly modelling fractures through multi-realizations enable to get a solution that match as much as possible the PTA. In the particular case of large reservoir with scarce data, it allows geologists to have an estimate of the fracturing state of the reservoir and how these fractures are contributing to the overall field flow behavior. It is also a way of mimicking the fracture pattern in the case of few data availability, and which ultimately will enhance the quality of the history match