GEO 2008

Developing fractured carbonate reservoirs has always been demanding for the geoscientists of the oil industry. The main challenge, in this regard, has been modeling the fracture system. To build a DFN (discrete fracture network) model, different geostatistical techniques are used to extrapolate the fractures beyond the well locations and populate them between the well control. However, due to inherent uncertainty DFN predictions have not always been correct, so the industry needs a way by which DFN models can be constructed with a higher degree of certainty. This presentation discusses an innovative workflow by which the borehole-scale fracture data is integrated with the surface seismic using the Fracture Cluster Mapping (FCM) technique to locate fracture clusters. The most important step in this approach is to obtain a good understanding of the fracture system intersected by boreholes that have certain expressions on the drilling record, borehole images, petrophysical logs, cores and production data. Generally the discrete fracture occurrences would not have any expression on the surface seismic. However when fractures of bigger dimensions form clusters/swarms, they tend to have larger vertical and horizontal extents, as observed in several outcrops in the Middle East and other countries. In this workflow, surface-seismic data processing is optimized for it to be used for fracture clusters / corridors detection. Having a good understanding of fractures’ pattern in the field and optimally processed 3-D seismic data, Ant Tracker (which is an essential part of FCM for automatic extraction of lineaments from the seismic data) is run on the seismic cube. The Ant Tracker set of parameters are conditioned based on the fracture data, gathered from boreholes, in such a way that they highlight fracture clusters/corridors of certain orientations and width. The workflow was tested on the study area of about 1,400 square km for the carbonates of low porosity, low permeability and about 3,000 ft thickness. There were 12 wells drilled in the study area and ten of them had image logs and cores (from selected zones) to get information on fractures. One well test, one production log, and mud loss data from half of the wells, and total well production data were used to understand the fracture behavior. Wellbore images and cores in the study area invariably showed existence of fracture clusters/ swarms of width greater than 100 ft and length greater than 500 ft.

The distribution of water saturation within an oil reservoir is of paramount importance for hydrocarbon volume, reserves and production assessment. Inter-facial interactions between oil, brine and rock determine the fluid saturations and distributions within the pore system. Only two fundamental electrostatic forces, acting between neutral molecules, are responsible for all of these interactions, i.e. the dispersive and the polar forces. It will be demonstrated that the latter interaction is the dominant force field for all the interactions at the interfaces with water and control the capillarity of an oil reservoir. These molecular forces determine the inter-facial tension between crudes and brines (σ) and the contact angle (ө) between the liquids’ interface and the surface of the rock. The resulting quantity σ.cos(ө) is the effective capillary stress resisting the buoyancy of the penetrating oil and strongly determines the ultimate amount of oil in the pores. Experimental work on these quantities has not progressed greatly over the last decennia, in particular for those related to carbonate reservoirs. In this presentation the physics related to intra-molecular attraction and the resulting inter-facial interaction is analysed. For example it will be shown that the gases dissolved in the crudes greatly affect the electrostatic properties of the crudes, effectively reducing the interactions with the brines and reservoir rocks. Moreover, it will be demonstrated that, owing to the properties of the carbonate rocks, the σ.cos(ө) values for carbonate oil reservoirs could be substantially lower than for clastic reservoirs. All these conclusions affect the apparent wettability of the reservoirs, with possible far-reaching consequences for reserves and production.

This presentation will discuss the identification and resolution of a water-bottom multiple problem encountered in the Arabian Gulf. In 2002, Saudi Aramco acquired and processed an ocean-bottom cable (OBC) survey configured with hydrophone and geophone sensors designed to attenuate seismic energy trapped in the water layer. Subsequent interpretation of the 3-D data volume at the target horizon revealed wavelet variations that mimicked the water-depth profile. This was of concern, as the target was not expected to be conformable to the water bottom. An investigation of the issue determined a significant amount of unwanted energy remained in the data, even after use of industry standard processing and acquisition methods. After careful analysis we found that rapid changes in the water-bottom reflection coefficient may have compromised the results by inadequately suppressing water-borne energy. A key diagnostic display in the common water-depth domain indicated it was possible to isolate the periodicity of this unwanted energy such that inverse filters could target and suppress it. A new workflow was then designed such that an algorithm utilizing multi-domain deconvolution could identify and suppress the errant energy while maintaining structural and wavelet integrity at the target horizon. The new workflow proved to be more efficient than traditional single channel deconvolution methods with respect to isolating the periodic nature of the water-borne energy. A repeat of the diagnostic displays indicated the new
workflow was measurably more effective at suppressing the residual water bottom multiple.

The objective of this study is to build an integrated geological model for a Jurassic reservoir in Saudi Arabia utilizing all available static and dynamic data to optimize field development plan and well placement. The Late Jurassic Arab Formation is one of the most important reservoirs in the Middle East. During this period a carbonate platform developed in most of the Arabian Gulf and extended to the Zagros Mountains in Iran and central Iraq. The reservoir consists of 45–50 ft of packstone to grainstone reservoir overlain by 5–15 ft of anhydrite. A total of 533 ft of cores from 13 wells have been studied and also results from 54 wells including well logs and well performance have been used. In this study, different sources of data with different scales were integrated to
produce a single model that best represents the reservoir. This project was carried out through three main stages. The first stage was a detailed reservoir characterization study for the reservoir including core description, rock and facies types, pore geometry and diagenesis. The second stage involved univariate and multivariate statistical analysis of input data such as well logs. In the third stage, an integrated stochastic reservoir model was built using different geostatistical modeling techniques. This newly generated model captured the reservoir heterogeneities and was used to optimize placement of horizontal wells and to predict reservoir performance. So far a total of seven horizontal wells have been drilled with 29,000 footage based on this study and the results
are very satisfactory in matching expectation.

In mature basins, most of the exploration is oriented towards satellite prospects. The difficulty in their detection lies in a reliable evaluation of their economic interest. Indeed, the interest in such prospects is very sensitive to the trap volume and the quality and composition of the producible hydrocarbon fluids. Trap volume and hydrocarbon quality can only be predicted through a detailed reconstruction of the reservoir and its hydrocarbon infilling evolution. It is necessary to take into account, as a function of the geological time: (1) the structural evolution and faulting of the area; (2) the initial facies distribution and diagenesis; and (3) the fluid maturation and migration with a fine compositional description. Such a time-related filling is classically taken into account at basin-scale but rarely applied to the fetch area of giant fields where the satellites are searched for. Here we propose an integrated approach that takes advantage of the well-known geochemical information from the discovered large structures to calibrate the trapping and composition of the satellite structures. The approach, which uses softwares originally developed for basinscale exploration, is based on the combination of tools for structural reconstruction (Kine3D), fine simulation of facies distribution (Dionisos), high-resolution compositional kinetics and migration/dismigration scenarios (TemisSuite) and uncertainty evaluation (QUBS).

In the Development Plan of Kuwait Oil Company, production from several minor reservoirs in northern Kuwait is scheduled to increase by about 10-fold by 2015–16. These reservoirs were not previously studied in detail because of limited experienced staff, most of whom had focused on the accelerated development of the major reservoirs in the country. Some of the minor reservoirs are complex, discontinuous and require further delineation. In some fields they are stacked and can potentially add many billions of barrels of oil in reserves growth. In order to accelerate the appraisal of these reservoirs, a multi-pronged approach was adopted to identify reserves growth and increased production opportunities. The approach involved: (1) identifying existing wells for testing; (2) deepening and testing of planned wells to the deeper Cretaceous Zubair and Ratawi reservoirs; (3) utilizing the Jurassic wells that penetrated through the Zubair and Ratawi reservoirs to acquire data; (4) identify opportunities to acquire data in wells penetrating
through Tuba and Mid Burgan during the ongoing drilling activities for major reservoirs; and (5) continued surveillance in the Burgan and Mauddud reservoirs in Bahra field, so as to assess the pressure-production performance. In order to expedite the tasks, a managementlevel steering committee was formed to supervise the implementation of a blueprint that listed all the activities in terms of timelines, priority matrices.

A giant carbonate oil field, located in Abu Dhabi, has been producing from Lower Cretaceous reservoirs since 1973. The current field development plan (FDP) is based on a reservoir model, which has evolved in stages, with input from many field and laboratory studies over the past 20 years. The most recent static model has been built incorporating the results from significant new core characterization and sequence stratigraphic studies (over 110 cored wells), in addition to a more thorough integration of well, geological, production and 3-D (and 4-D) seismic data. Modeling such a large and active field (more than 600 wellbores) presents real data management challenges. These challenges include the choice of geo-modeling software, accessing and maintaining the corporate database, and ensuring that all engineering and geosciences disciplines are able to easily contribute and use the final integrated model. This new Phase-3 static model has been built primarily to provide a more detailed reservoir description to the dynamic model to further optimize the FDP, as we complete the current infill drilling campaign and move to the tighter infill production. The model is also meant to provide a longer-term, more robust geological characterization for future enhanced oil recovery (EOR) activities. A recurring theme for the team is also the challenge to find the appropriate balance between incorporating 3-D seismic data and using data from the densely located wellbores. Other new demands on our modeling workflows include the need to quantify volumetric uncertainties by generating model scenario’s and multiple realizations for proven SEC (US State Securities and Exchange Commission) deterministic and probabilistic reserves reporting. The new workflows will also allow a more rapid model updating as new wells are drilled.

The success of the Late Aptian, Upper Shu’aiba Formation play in Block 6, northern Oman has been driven by an increased understanding of the depositional architecture of the basin. It is founded on the integration of seismic attribute data with a well-based sequence stratigraphic framework, palaeo-environmental data and data from analogue fields. The Upper Shu’aiba sequence was deposited along the southern margin of the Bab Basin in the Late Aptian, during a regional lowstand. In northern Oman, deposition occurred in a strait between the isolated Safah Platform and the early-Late Aptian Shu’aiba margin to the southeast. The succession on the northern flank of the strait, which is largely mirrored on the south, is characterized by progradational geometries, with carbonate shoals intercalated with argillaceous limestones or marls. The shoal trends can be imaged seismically as a succession of amplitude and spectral decomposition tuning belts and have been modelled in PetrelTM. The clinoforms have ramp or distally steepened ramp morphologies, with palaeo-water depths ranging from 100 m to less than 5 m, with facies transitions from outer-ramp mudstones, through mid-ramp wackestones and packstones into inner-ramp shoal or build-up facies, locally with low-energy backshoal facies. The shoals vary from rudist-dominated rudstones and floatstones in Ufuq to coated-grain and miliolid-dominated grainstones in Dafiq, which reflect variations in depositional energy regimes and accommodation space during the gradual infilling
of the strait from the north (and south). Reservoir properties are largely controlled by the primary depositional fabric, however, significant diagenetic overprinting, both enhances and degrades the reservoirs.

Extensive field studies in the Hawasina Window region
of the Oman Mountains led to the recognition of
four major structural processes, linked with: (1) intraoceanic
obduction; (2) emplacement of ophiolites onto
the Arabian continental margin; (3) unroofing of the
subthrust margin; and (4) Tertiary folding and extension.
The first Cenomanian process is not relevant to the
formation of hydrocarbons in the Arabian margin. The
second Turonian process led to the formation of out-ofsequence
nappes and ductile extension. It provided tectonic
burial of the margin. An omnipresent NE-vergent
syn-cleavage folding is also associated to emplacement.
The shortly following tectonic unroofing rafted ophiolite
blocks away from the window areas. Break-up of the
nappes is suggested along a pre-existing strike-slip fault
system. Isostatic compensation led to uplift and folding
of the nappe succession. Finally the Tertiary Period was
characterised by across-strike normal faulting and numerous
steps of folding, ramp-thrusting and transpression.
This process uplifted potential reservoir sections in
Late Tertiary times. The play concept proposes classical
Natih source rocks and reservoirs in the autochtchon.
Since original porosity is reduced due to tectonic loading,
fracture porosities in the limestones and Upper
Permian-Triassic dolomites are considered viable in the
reservoir rocks. Seals are formed by shaly sections of the
autochtchon (Salil, Nahr Umr and Muti formations) and
of a regional evaporitic detachment at the base of the
Hawasina Nappes. The major upwarp of autochtchon
and three local antiforms in the Hawasina Window form
the potential trap(s). Vitrinite reflectance and clay mineralogy
both reflect anchimetamorphic conditions for the
Hawasina Nappes. Thermal conditions probably did not
exceed late-stage, gas maturity levels. The main burial is estimated to have lasted for 10 million years. Therefore
the Hawasina Window area is considered gas-prone.
Both MOL Hungarian Oil & Gas Plc and Hawasina LLC
Oman Branch wish to thank the Exploration Directorate
of Ministry of Oil & Gas of the Sultanate of Oman for the
continuous support to the work.

Passive seismic methods have been traditionally applied to study the Earth’s internal structure using earthquake data. It is only recently that these methods have been used in petroleum reservoir delineation. Monitoring of fluid pathways in a producing reservoir is imperative for optimal reservoir management and maximal oil recovery. A pilot microseismic experiment has been designed and implemented in a Saudi Arabian oil field for mapping of Arab-D Reservoir drainage patterns. The experiment is unique because of the large array of permanent multicomponent seismic sensors that are deployed at various levels in the borehole and over a surface area surrounding the borehole. The passive microseisms are recorded simultaneously in the surface and borehole sensors. The
field pilot will test the ability for recording microseismic events caused by Arab-D Reservoir production and injection activities. The combined surface and boreholebased measurements are designed to provide a wide areal coverage over the reservoir. The sensor network is designed to capture events of greater than Richter magnitude -3, with frequencies from 10 to 1,000 Hertz within two kilometers of the hypocenters. In addition to microseismic, permanent pressure and temperature sensors were installed in the wellbore. Fluid-flow anisotropy in the area is evident from production behavior and well test data but the flow pathways and mechanism for the anisotropy are not resolved. Microseismic data could provide the location and relative fracture density that will improve the reservoir-flow, simulation models. Monitoring microseismic events over time will enable better prediction of fluid-flow behavior and the planning of production and injection well locations for optimizing reservoir production and ultimate recovery.