Carbonate rocks are complex in their structures and pore geometries and often exhibit a challenge in their classification and behavior. Many rock properties remain unexplained and uncertain because of improper characterization and lack of data QC. The main objective of this paper is to study flow behavior of relative permeability with different rock types in complex carbonate reservoirs.
Representative core samples were selected from two major hydrocarbon reservoirs in Abu Dhabi. Rock types were identified based on textural facies, PoroPerm characteristics and capillary pressure. Porosity ranged from 15% to 25%, while permeability varied from 1 mD to 50 mD. Primary drainage and imbibition water-oil relative permeability (Kr) curves were measured by the steady-state technique using live fluids at full reservoir conditions with in-situ saturation monitoring. High-rate bump floods were designed at the end of the flooding cycles to counter capillary end effects. Aging period of 4 weeks was incorporated at the end of the drainage cycle. Robust data QC was performed on the samples, and final validation of the relative permeability was conducted by numerical simulation of the raw data and measured capillary pressure.
The followed QC procedure was crucial to eliminate artefact in the relative permeability curves for proper data evaluation. The different rock types showed consistent variations in the relative permeability hysteresis and end points. Imbibition relative permeability curves showed large variations within the different rock types, where Corey exponent to oil ‘no’ increased with permeability from 3 to 5, whereas the Corey exponent to water ‘nw’ decreased with permeability and ranged from 3 to 1.5. The variations in the relative permeability curves are argued to be the result of different rock structures and pore geometries. Variations were also seen in the end-point data and showed consistent behavior with the rock types.
The different carbonate rock types were identified based on geological and petrophysical properties. Higher permeability samples were grain-dominated and more heterogeneous in comparison to the lower permeability samples, which were mud-dominated rock types. Imbibition Kr curves showed larger variations than the primary drainage data, which cannot be interpreted based on wettability considerations only. The relative permeability curves have been thoroughly evaluated and QC'd based on raw data of pressure and saturation by use of numerical simulation. Such RRT-based Kr data are not abundant in the literature, and hence should serve as an important piece of information in mixed-wet carbonate reservoirs.
Equilibrium Pc-RI measurements on low permeability core plugs present the SCAL laboratory with some difficult challenges regarding the duration of measurements and the attainment of truly equilibrated resistance readings. A new empirical method is described that allows estimation of fully equilibrated resistance by application of a simple transient data linearizing transform and plot slope analysis. A small set of plugs from a conventional tight gas field in the Sultanate of Oman is used to demonstrate the method. The method may also be used by the lab to monitor and shorten the Pc-RI measurement duration without compromising the interpretation of saturation exponents or capillary curves. Transform plot transients and macro capillary number are examined to estimate a boundary where the plugs transition from shock front rapid desaturation to slow percolation desaturation behavior.
This paper introduces an analytical approach for generating the inflow performance relationships (IPR) of different reservoirs depleted by different wellbore types at different conditions. The main focus of this paper is given to multiphase flow (oil, gas, water) and two-phase flow (oil, gas) during transient and pseudo-steady state flow conditions. The proposed approach presents new integrated models for the IPR that correlates the wellbore pressure with the multiphase total flow rate or the normalized pressure and rate by the bubble point pressure and single-phase flow rate at this pressure. These models consider the changes in reservoir fluid physical properties and reservoir relative permeabilities by coupling PVT data and relative permeability curves. The motivation of this study is reducing the uncertainty in the IPR of reservoirs undergoing the multiphase flow.
Predicting multiphase IPRs may go throughout three tasks. The first is developing the pressure functions of reservoir mobility and total compressibility by developing several correlations for reservoir fluid properties such as oil, gas, and water formation volume factor as well as gas solubility in oil and water. Several correlations are needed also for relative permeability behavior of the three fluids with the pressure. These correlations can be generated by the multi-regression analysis of PVT data and relative permeability curves. The second represents developing the analytical models for the flow regimes that could be developed during the entire production life of the reservoirs. The single and multiphase flow IPRs for different flow regimes are predicted in the third task. The proposed IPR in this study is plotted between the wellbore pressure and the total flow rate at reservoir condition or the normalized reservoir pressure and flow rate.
The observations obtained from this study are: 1) The proposed approach for the multiphase flow IPRs is not only time-variant but also depends on the flow condition whether transient or pseudo-steady state flow. 2) The IPR of the multiphase flow gives lower performance than the single-phase flow. 3) The IPR of the early time transient production is better than the late time pseudo-steady state production. 4) It is highly recommended to develop the models of fluid properties for each reservoir instead of using the models presented in the literature.
The novel points presented in this paper are: 1) Introducing a new approach for the inflow performance relationships in the reservoirs experiencing multiphase flow and depleted by horizontal wells or multiple hydraulic fractures. 2) Introducing the pressure functions of the multiphase flow reservoir mobility and multiphase flow total reservoir compressibility that consider the changes in reservoir fluid properties and relative permeabilities with production time and pressure in constructing the IPRs.
Relative-permeabilities are a first-order parameter to consider when describing multiphase-flows in porous media. Among many other parameters, the core wettability controls the fluids repartition in the porous media at pore-scale, strongly affecting how the fluids can be displaced (i.e. their relative-permeabilities). As the initial core wettability of reservoir sampled cores is rarely preserved, classical SCAL measurements (such as relative permeabilities) may not reflect the rock properties at reservoir conditions. This originate core wettability may be restored in a process referred as ‘core aging’. It is generally done by injecting the reservoir fluids (brine and crude-oil) in the core to equilibrate the rock surface with respect to the oil and brine components. Here, we investigated the effect of two aging protocols (static and dynamic) on wettability restoration, and characterize the aging using oil/water relative permeabilities measured on the core after aging. The two aging protocols were applied on a set of initially strongly water-wet outcrop sandstone samples (Bentheimer). The relative permeabilities were measured using the steady-state method and a state of the art experimental setup (CAL-X) based on X-ray radiographies. The setup is equipped with an X-Ray radiography facility, enabling monitoring of 2D local saturations in real-time and thus giving access to fluid flow paths during the flooding. Aged samples relative permeability curves show clear differences when compared to water-wet relative permeabilities, hence suggesting that the wettability has been effectively altered. However, the two aging protocols were unable to produce the same results. The dynamic aging has led to an inversion of the original relative permeability curves asymmetry, suggesting a strongly oil-wet system, whereas the static aging protocol has altered the wettability to a lesser extent. The differences can be explained by analyzing a 2D saturation maps. In the case of dynamic aging we observed a homogeneous distribution of fluid saturation during fractional flow. On the opposite, the static protocol results in heterogeneous flow paths, confirming that this protocol did not alter uniformly the wettability of the sample and generates a patchier mixed-wettability system.
We investigated the method of estimating porosity/permeability using X-ray CT, a non-destructive method. Using X-ray CT, a method of estimating the porosity/permeability is particularly developed in sandstone. However, for the carbonate rocks, the internal structure is complicated due to biological origin. This is difficult to recognize the pore space, therefore a method of estimating the porosity/permeability using X-ray CT has not been studied. This study is based on
Based on the 3D modeling of the X-ray CT, two rudist families (Radiolitidae and Ichthyosarcolites) were identified through their morphological characteristics such as inner diameter and shell thickness. A porosity of slab core around 50 feet is about 18% from CCA (Conventional Core Analysis). This slab core is made up of small rudist populations (length and wide size is 15-10mm), inside core confirmed 3D modeling (surface rendering and volume rendering), and calculated porosity is 0.89% from RCM (Reverse Coupling method). It is understood that this difference is dependent on matrix porosity and further investigation in the future is required in order to measure matrix porosity using thin section and micro X-ray CT. With regards to reservoir properties, the porosity is higher in the lower part than the upper part in the core interval. The size of the Radiolitidae could be dependent on the environment and its vertical variation suggests the change of depositional environment. Larger Radiolitidae, which appeared from 80 to 200 feet below the C-T (Cenomanian-Turonian) boundary, suggests a relatively strong wave influence. From a sedimentological point of view, the coarser matrix grain size supports the interpretation of depositional setting. On the other hand, from 30 to 80 feet below C-T boundary, smaller Radiolitidae is dominated. It was assumed that small Radiolitidae could be due to high physical stress under a restricted environment.
This study shows the advantage of X-ray CT image in rudist recognition, based on interpretation of depositional environment and understanding the reservoir property. The result of this study suggests the strong correlation between porosity/permeability and depositional environment (accommodation space) inferred from rudist fossil.
In carbonates, predicting permeability values for gridded reservoir models is very challenging as it involves both the difficult characterization of a very heterogeneous medium, the uncertain extrapolation far from well data, and the up-scaling concern. The quantification of effective permeability for model gridblocks using small scale data from plug measurements or log interpretation is a recurrent concern since the change of support for permeability has proved to be definitively non linear. When a well test interpretation is available, it gives the evolution of the permeability in the vicinity of the wells for a volume much larger than the volumes characterized by cores and logs. In that case, the consistency has to be found between the transient pressure analysis-derived large scale equivalent permeability and the small scale permeability issued from conventional core analysis or log interpretation.
It is known that the upscaling can be expressed as some power average of the permeability distribution, and that an analytical formula relates the horizontal permeability in the volume investigated by the well test and the original small-scale permeability distribution in this volume. However, the relation between the upscaling law and the permeability structures is usually documented for a few number of structures, leading to recurrent problems when large scale permeability has to be extrapolated outside the volume explored by the well test.
A new formulation of the power averaging coefficient has been proposed, which relates the power averaging coefficient to the geostatistical description of the permeability structures, the direction of the flow, and the volume for which the equivalent permeability is computed. The new methodology has been applied to the Buissonniere field laboratory, a site from the ALBION R&D Project. Thanks to a characterization at an unusual scale, the integration of geological, petrophysical, geophysical and pressure transient data has successfully validated the use of this new formulation.
Building accurate reservoir models can be quite challenging, especially highly stratified thick intervals in hydraulic communication in reservoir. Presented methodology is based on comprehensive Interval and Interference Pressure Transient Testing (IIPTT) for classified reservoir types with a systematic approach. Classification of reservoir types is based on layering, thickness, and hydraulic communication of layers in the reservoir. The methodology describes building more accurate anisotropic reservoir models, providing well performance assessment based on integrated comprehensive IIPTT solving with efficient nonlinear parameter estimation and modeling with numerical simulation for different reservoir types. The number distributed IIPTTs are optimized to ensure to achieve coverage across total thickness depending on the reservoir type. It is demonstrated that high resolution accurate reservoir models can be built for relatively thick highly layered reservoirs in a feasible manner.
Chakib, Ouali (IFP Energies nouvelles, 1 et 4 avenue de Bois Préau, 92852 Rueil-Malmaison, France) | Elisabeth, Rosenberg (IFP Energies nouvelles, 1 et 4 avenue de Bois Préau, 92852 Rueil-Malmaison, France) | Loic, Barre (IFP Energies nouvelles, 1 et 4 avenue de Bois Préau, 92852 Rueil-Malmaison, France) | Jean François, Argillier (IFP Energies nouvelles, 1 et 4 avenue de Bois Préau, 92852 Rueil-Malmaison, France)
Two innovative characterization techniques, Small Angle Neutron Scattering (SANS) and High Resolution Fast X-ray Micro-tomography on a Synchrotron, have been combined to usual coreflood environments and X-Ray CT Scanner measurements in order to describe the texture of a foam flowing in an opaque 3D porous medium. SANS measurements give access simultaneously to the gas saturation and to the amount of gasliquid interfaces developed per unit volume and therefore to the in situ specific surface area of the foam denoted S/V. In situ texture of the foam flowing in real 3D porous media is therefore measurable. Fast X-Ray micro-tomography 3D images of foam flowing in a porous medium give visual evidence of the presence of gas bubbles in areas where the flow rate is naturally slowed by the trapping phenomena and enable to describe and follow the phenomena of intermittent trapping at the pore scale.
Ali, Arfan (Brunei Shell Petroleum) | Jofri, Azimah (Brunei Shell Petroleum) | Zamikhan, Norshah (Brunei Shell Petroleum) | Borah, Jahnabi (Brunei Shell Petroleum) | Yahya, Mohd Noor Isa (Brunei Shell Petroleum) | Van Den Heuvel, Erik (Brunei Shell Petroleum) | Kim, Igor (Shell Global Solutions International) | Hardikar, Nikhil (Baker Hughes, a GE company) | Coskun, Sefer (Baker Hughes, a GE company)
Since the advancement of Focused Sampling techniques, wireline formation fluid sampling has undergone a dramatic change. This has primarily been due to the promise of acquiring representative formation fluid samples with minimal mud filtrate contamination and large sample volumes, thereby adding value to the PVT laboratory studies as well as reducing the fluid sampling time, thus aiding significantly to the cost savings. This paper demonstrates the contribution of focused sampling technology for reservoir fluid mapping in numerous exploration and development wells in South East (SE) Asia, by optimized selection of different packer types based on varying reservoir properties.
For the exploration wells, the primary objective was to determine the non-hydrocarbon (non-HC) content (CO2 and H2S in this case) of the single-phase reservoir fluid samples, which were expected to be close to the saturation pressures. Following the 3D near-wellbore simulations, an elongated and an extra-elongated focused packer were selected due to expected low permeabilities, reservoir thickness and wellbore conditions. The wells were drilled in managed pressure drilling (MPD) conditions, with overbalance ranging from 900 to 4,300 psi. The development campaign consisted of five producers with key objectives of determining fluid type and the non-HC (CO2 in this case) content along with assessing the reservoir/block connectivity. The concentration and uncertainty in CO2 distribution would have a major impact in developing the production strategy of the area. A standard focused packer was selected for the sampling jobs which were carried out on pipe due to high overbalance conditions (~2,400 psi).
In the exploration wells, 30+ samples (gas, oil and water) were collected with the time-on-wall ranging between 1.5 and 7 hours. In the development campaign, 50+ samples (gas and oil) were collected with the time-on-wall ranging between 45 minutes and 2.5 hours. Given the depths and low permeabilities of the reservoirs with high overbalance, this resulted in significant time savings. The larger flow area of the elongated and extra-elongated focused packers ensured minimal contamination in the collected samples given the challenging sampling conditions, where restrictions to pressure drawdown existed. The PVT laboratory results showed ‘insignificant’ oil-based mud filtrate contamination in the samples. In addition, the large sample volumes provided flexibility for additional PVT studies and improved resource assessment.
The focused sampling technology was successfully applied in both exploration and development campaigns in the SE Asia region. The pre-job simulations ensured optimal packer selection between the three focused packer types. The comparison between the actual sampling results and the 3D near-wellbore simulation would help optimize future sampling operations in the area. In addition, the two campaigns have reiterated a clear value of information in saving cost, reducing contamination in the samples and technology success in the given environments.
Al-Saeed, Abdullah (Kuwait Oil Company) | Al-Dhafiri, Anood (Kuwait Oil Company) | Fidan, Erkan (Kuwait Oil Company) | Al-Mutawa, Majdi (Kuwait Oil Company) | Abdul Hadi, Ahmad (Packers Plus Energy Services Inc)
Selecting the completion design and stimulation technique in North Kuwait Jurassic Gas (NKJG) were critical to overcome reservoir challenges by stimulating these unconventional formations efficiently and effectively. Therefore, the completion design must be high-pressure rated upto 15,000 psi, high temperature of 275°F and sour service specified because of high H2S & CO2 content. These reservoirs are heterogeneous carbonate type with various productivity index due to existence of natural fracture which needs proper completion type that treat each reservoir layer separately. The most challenging factor in these unconventional reservoirs is the high permeability contrast among the different flow units because of the dual porosity effect which needs convenient diversion mechanism during the stimulation. The reservoir was segmented into different intervals to enhance the productivity index of each flow unit.
For that reason, "High Rate Matrix Acidizing (HRMA)" method was obtained with retardard acid to restore the well productivity due to the drilling fluids which alter the effective permeability near the wellbore. By dividing each flow unit into separate stages across packer system and stimulate them subsequently is the aim to overcome high permeability contrast across the reservoir flow units.
The Monobore Multi-stage was chosen as a completion type to produce from different zone of interest. These Reservoirs are divided into different stages and acid treated with various stimulation techniques (Acid fracturing & High Rate Matrix Acidizing). The success of the stimulation treatment in monobore Multi-stage completion depends on several factors such as: selecting proper fluid recipes, rock/fluid properties, job design, and field implementation. That type of completion is activated as a drop-ball system to stimulate each flow zone individually but in single well intervention setup.
This paper presents a 15K open-hole HPHT MSC field success case application that describes the best practices, learning, planning, design, installation and stimulation in NKJG unconventional reservoirs to enhance well performance and overcome reservoir challenges. An improvement in understanding of production performance from several reservoir sections is the key enabler selective stimulation and effective testing. After stimulating all the stages milling of the ball seats of completion was obtained in order to pinpoint well production profile. The post stimulation flow tests results and production logs provided a good evidence for applying this technology these unconventional reservoirs.