The development and management of naturally fractured reservoirs (NFRs) is a challenging task for asset teams due to the complexity of these reservoirs. The challenges are observed from the initial exploration phase and continue up to the field development stage. Placing production and injection wells in NFRs pose serious challenges. In most cases, highly permeable fractures are encountered during drilling leading to substantial loss of drilling fluids and extensive use of loss circulation materials. Thus, asset teams need to proactively predict location of these highly conductive fractures since they act as channels for rapid water or gas movement leading to early breakthrough and poor volumetric sweep efficiency.
Carbonate sediments are commonly formed in shallow, warm oceans either by direct precipitation out of seawater or by biological extraction of calcium carbonate from seawater to form skeletal material. The result is sediment composed of particles with a wide range of sizes and shapes mixed together to form a multitude of depositional textures. The sediment may be bound together by encrusting organisms or, more commonly, deposited as loose sediment subject to transport by ocean currents. A basic overview of carbonate-reservoir model construction was presented by Lucia, and much of what is presented herein is taken from that book. Depositional textures are described using a classification developed by Dunham. The Dunham classification divides carbonates into organically bound and loose sediments (see Figure 1).
Merza Media, Adeyosfi (Schlumberger) | Muhajir, Muhajir (Pertamina Hulu Energi Tuban East Java) | M. Wahdanadi, Haidar (Joint Operating Body Pertamina Petrochina East Java) | Agus Heru, Purwanto (Joint Operating Body Pertamina Petrochina East Java) | Anugrah, Pradana (Schlumberger) | Dedi, Juandi (Schlumberger)
Most of sedimentary basins in Indonesia contain productive carbonate reservoirs. Geologically, the reservoirs are mostly part of a reef complex and carbonate platform, with basinal areas situated mainly in the back arc of the archipelago. Many of the productive carbonate reservoirs have dual porosity systems with widely varying proportions of primary and secondary porosity. Carbonates of the Tuban formation in Platinum field represent two carbonate buildups identified with similar effective porosity but different productivity. This paper describes a method for characterizing secondary porosity distribution at the wellbore and field scales to address the productivity difference between the northern and southern carbonate buildups in this field.
To resolve the challenges in characterizing secondary porosity in a carbonate formation, an integrated workflow was developed that consists of combination of quantitative and textural analysis based on borehole images at the single-wellbore scale and the seismic inversion result to control lateral distribution at the field scale. Analysis based on borehole image log provides high-resolution porosity characterization based on its size, interconnectivity, and type. The result of the single-wellbore analysis will be distributed at the field scale with control of a seismic attribute such as acoustic impedance (AI). Acoustic impedance is built with stochastic seismic inversion to provide a higher-resolution result compared to the deterministic seismic inversion method.
The result of the analysis based on borehole images at the single-wellbore scale shows most of the northern carbonate buildup wells demonstrate high development of porosity from interconnected vugs, leading to a relatively high permeability interval. In contrast, the southern carbonate buildup wells demonstrated low secondary porosity development. Low secondary porosity development is related to cemented zones and the predominance of claystone facies in a well. Later, the result of the single-wellbore scale analysis was distributed at the field scale with seismic attribute control such as AI. The Platinum field shows a negative correlation between AI and porosity with a value of -0.769; hence, the acoustic impedance from stochastic seismic inversion can be used to control the porosity distribution. The secondary porosity model shows a distinct difference between the northern and the southern carbonate buildups. The northern carbonate buildup has higher average secondary porosity compared to the southern carbonate buildup. The result was confirmed with production data; the northern carbonate buildup has higher productivity compared to the southern carbonate buildup.
This integrated workflow provides a comprehensive and high-resolution analysis of secondary porosity distribution at the single-wellbore scale and the field scale. Thus, this workflow can reduce uncertainty during reservoir characterization, well placement, and production planning.
In order to understand the large scattering of elastic properties of carbonate rocks, two datasets were chosen in two different geological formations (non-tropical carbonate from Australia and actual continental carbonate from Turkey). Three statistical methods that aim to quantify the influence of Geological depositional environment and dominant pore type, that highlight similarities and differences on petro-elastic and petrophysic behaviors. Geological depositional environment information would be main reason for Vp variation as shown by Study 1, while in study 2 pore-type could have a strong link with P-wave velocity. To understand the origin of those similarities and differences, and to identify common information hidden inside the geological meanings, several simulation tests have been performed by digital rocks, in order to quantify the influences of the pore volume fraction, pore size and pore shape of carbonate microstructure. The numerical simulation shows that the pores size has statistically no influence on the elastic response; the pore shape is one of the main impacting parameter of the elastic properties. The future work consists on the understanding of influence factor for petrophysic parameter by more simulation results. The ultimate objective of this study is to identify factors that influence seismic velocity and then use it to better interpret the petrophysic parameters from seismic inversion.
Hadidi, Shahab (Petroleum Development Oman) | Yaarubi, Hilal (Petroleum Development Oman) | Baaske, Uwe (Petroleum Development Oman) | Suwannathatsa, Sakharin (Petroleum Development Oman) | Farsi, Shadia (Petroleum Development Oman) | Bazalgette, Loic (Petroleum Development Oman) | Hamdoun, Lana (Petroleum Development Oman)
The infill potential of one of the most complex fractured carbonate reservoirs in the Sultanate of Oman has been evaluated through the integration, visualization and analysis of different data sources. The field has been split into different simplified genetic geobodies which contain the culmination of facies changes that define rock quality, fluid fill, oil saturation distribution and fracture network, amongst other properties that affect fluid flow. The long production history of more than 45 years, along with the large number of logged long horizontal wells scattered around the field, were key enabler for the analytical methodology.
Production data, coupled with resistivity logs in horizontal wells, viewed through time were the backbone of the analysis. Data analysis was achieved by combining these data in a single platform and performing the analysis at different slices of time. At each timeslice, different interpretations were inferred that explain the observed production behaviour and remaining oil saturation from the logged wells. The interpretations were narrowed down into a minimum number of realizations by combining interpretations from the same area gathered from different slices of time.
The analysis has resulted in the identification of four genetic performance regions in the field. Each region approximates a primary depositional facies belt and has a general defined relative behaviour of initial wells potential, water-cut development, initial and remaining oil saturation and, most importantly, infill wells potential. The analysis has aided in narrowing the subsurface uncertainties and has given a promising explanation for the large variations in wells behaviour. Infill wells opportunities have been identified, selected and ranked relatively in each of the regions.
The value of data analytics on large volumes of acquired information normally not used was demonstrated. Visualization of different data sources in one platform is a challenging task that usually stops engineers from experimenting. The team has found fit for purpose solutions to visualize different data sources through time. The shift of mind-set from uncertain complex models and evaluations into finding simple genetic performance regions of the reservoir was vital in unravelling infill potential.
Ahmadi Reservoir is one of the Reservoirs producing in the Bahrain Field. It has been producing for more than eighty years. Ahmadi is a tight carbonate Reservoir that belongs to the Wasia Cretaceous group. It consists of two main limestone units which are AA and AB. Like most Carbonates in the Middle East, Ahmadi production is dominated by secondary permeability which means that the reservoir has a dual exponential type Curve. Dual exponential in Ahmadi means a high flush initial production period and then a longer period of stabilized production.
Because of this behaviour, using conventional methods to monitor reservoir performance could be misleading. Hence, a new parameter was created to make sure that reservoir performance monitoring accounts for production in a more representive way. This parameter was called Normalized Production Index.
Normalized Production Index has been used to analyse reservoir performance in Ahmadi Reservoir as it accounts for both the flush rate and the stabilized production rate of wells. This parameter helps monitor and observe reservoir performance as it effectively identifies low and high productive areas, and hence leads to better decisions during reservoir development planning.
In this study, a Normalized Production Index of more than 246 wells was considered. These wells vary in area, dip direction, trajectory, and Horizontal length. The objective was to determine the most effective way of these to maximise production in Ahmadi.
Based on the analysis done using Normalized Production Index, it was found that the average oil production for horizontal wells is more than double that of a vertical/directional well. It was also found that wells oriented in an up-dip direction of the structure are performing better than wells oriented in a down-dip direction of the structure in some areas. These conclusions were considered in managing the reservoir. Some actions were taken based on these conclusions and resulted in positive performance, which verified the effectiveness of the Normalized Production Index.
Nath, Fatick (University of Louisiana at Lafayette) | Salvati, Peter E. (University of Louisiana at Lafayette) | Mokhtari, Mehdi (University of Louisiana at Lafayette) | Seibi, Abdennour (University of Louisiana at Lafayette) | Hayatdavoudi, Asadollah (University of Louisiana at Lafayette)
Understanding the mechanical behavior (compression, shear, or tension) of rocks plays an important role in wellbore-stability design and hydraulic-fracturing optimization. Among rock mechanical properties, strain is a critical parameter describing rock deformation under stress with respect to its original condition, yet conventional methods for strain measurement have several deficiencies. In this paper, we analyze the application of the optical method digital-image correlation (DIC) to provide detailed information regarding fracture patterns and dynamic strain development under Brazilian testing conditions. The effects of porosity, rock type, lamination, and saturation (freshwater and brine) on indirect tensile strength are also discussed.
To examine the effect of rock type, 60 samples of sandstone (Parker, Nugget, and Berea) and carbonate rocks (Winterset Limestone, Silurian Dolomite, Edwards Brown Carbonate, and Austin Chalk) were tested under dry and saturated conditions with regard to lamination angle in laminated samples. A photogrammetry system was used to monitor the samples in a noncontact manner while conducting the indirect tensile experiment. DIC depends on the photogrammetry system, which helps to visualize and examine rock-fracture patterns from the recorded images of the rock before and after deformation by assessing the strain development in samples.
The experimental results show the following.
Tariq, Zeeshan (King Fahd University of Petroleum & Minerals) | Abdulraheem, Abdulazeez (King Fahd University of Petroleum & Minerals) | Mahmoud, Mohamed (King Fahd University of Petroleum & Minerals) | Ahmed, Adil (King Fahd University of Petroleum & Minerals)
Linear elastic behavior of rocks is represented by two parameters, Poisson's ratio and Young's modulus. Proper estimation of elastic parameters of reservoir rocks is very important in alleviating the risk associated with oil and gas well drilling. The reasonable estimation of these two parameters also helps optimize well placement, mud-weight window calculations, appropriate completion design, and fracture orientation geometry. All these factors contribute to maximizing hydrocarbon recovery. Improper estimation of elastic parameters may falsely lead towards large investment decisions and unsuitable field development strategies. Poisson's ratio is very sensitive to the way it is estimated from laboratory data. Simultaneously, it plays a critical role in developing a profile of horizontal stresses and therefore its improved estimation is highly desirable.
Retrieving cores through the depth of the interest and conducting laboratory experiments on them under simulated reservoir conditions is the most appropriate way to measure these parameters but this approach is very expensive as well as time consuming. Often, most wells have very limited core data (possibly due to economics). On the other hand, log data are always available. Therefore, most often these parameters are estimated from the log data using empirical correlations. Most of the empirical correlations were developed using linear or nonlinear regression techniques which may not be generalized for unseen data. Artificial intelligence (AI) tool once optimized for training can predict elastic parameters more accurately than the nonlinear regression techniques, because AI tools can capture highly complex and nonlinear relationships between the input and the target data.
In this study, an improved model to predict static Poisson's ratio is presented. The model uses geophysical well-log data as input and laboratory experimental data as output. Functional network (FN) is used as an AI tool to model Poisson's ratio prediction. The dataset on which the AI model is trained was obtained from different wells in a giant carbonate reservoir that covers a wide range of values. To translate the FN model into a simple mathematical form, neural functions and empirical coefficients were extracted from the trained FN model. This allowed us to develop FN-based equivalent empirical correlation to predict static Poisson's ratio. The use of the proposed equation is very cost -effective in terms of saving the cost of core retrieval and conducting laboratory experiments. The proposed equation can be employed without the use of any AI software. The developed model, with empirical correlations, can serve as a useful tool to assist geomechanical engineers in estimating the profile of static Poisson's ratio in a given reservoir.
Heterogeneus deep carbonate reservoirs require enhanced development strategies to maximize reservoir contact and ultimately to increase the recovery factor. In some complex carbonate reservoirs, conventional strategies for reservoir development are not always the best choice and new technologies have to be applied to optimize the reservoir development. In such cases, underbalanced coiled tubing drilling (UBCTD) has proven to be a suitable approach to exploit more complex reservoir areas, where conventional drilling and stimulation techniques no always meet well productivity expectations.
The UBCTD technology consists of drilling a well with a drilling fluid pressure lower than the reservoir pressure, which tends to minimize the formation damage. Due to the underbalanced condition imposed in the wellbore, the well is allowed to flow naturally during drilling, while its productivity is measured. Another technique that accompanies this strategy is called bio-steering, in which cuttings are inspected while drilling to detect micro-fossils from the reservoir. Based on the real-time well productivity and the micro-fossils appearance, the well trajectory can be adjusted and corrected during drilling to chase the good wellbore productivity layers.
A number of wells has been drilled using this strategy with encouraging results so far, which opens a great window to continue exploiting the reservoirs under development. With this technology, multilateral placement is possible with a high degree of accuracy across thin reservoir layers, which maximize the reservoir contact and increases the well productivity. This work presents a general description of this technology as well as present a successful field case including all stages from well planning to well execution and testing.
Carbonate reservoir complexities are both described and hidden by the use of the common and generic term, "heterogeneous", with usually little serious effort then expended to define and quantify the meaning and dimensions of the term. Saudi Aramco, the custodian of the world’s largest petroleum reserves in carbonate reservoirs, is making long-term efforts to bring light to the carbonate "heterogeneity" darkness. We are constructing the industry’s largest integrated petrophysical and geological databases for our major carbonate reservoirs.
Our large databases contain porosity, permeability, grain density and pore system information from core plugs carefully integrated with a full suite of well log data and core descriptions. These cores have been described in detail using the most current carbonate sequence stratigraphic techniques and all these data have been captured digitally and integrated consistently and carefully. Our database for one field contains 1695 limestone pore systems (a pore system is defined by a single Thomeer hyperbola), obtained from 931 plug samples by Thomeer analysis of core plug mercury capillary pressure data (MICP) with plans to expand the measurements to 1500 plug samples for just this one major reservoir by the year 2020. The current core plugs for the database now include samples from 30 cored wells (up from the 10 cored wells of the previous Rosetta Stone project) to obtain statistically robust reservoir petrophysical data at the facies level. Pore system data are now also being acquired in vertical wells for constrained reservoir layering and vertical reservoir model tie points using nuclear magnetic resonance (NMR) well log data and the CIPHER software for the Thomeer parameter MICP-consistent spectral porosity analysis.
At Saudi Aramco, our extensive facies – petrophysical properties database process delivers the reference reservoir property database for our major carbonate reservoir models. The reference database improves our understanding and modelling of the variation and covariation of the facies and petrophysical rock types (PRTs) for reservoir modeling. It also provides sound statistical support for the population of the reservoir with petrophysical pore system properties within the sequence stratigraphic facies framework. For the reservoir dynamics, the database allows detailed investigations into the statistical linkages of pore system properties which control permeability and relative permeability developed by Clerke and coworkers to the sequence stratigraphic reservoir facies.
We report here selected results from a very large quantity of relationships and statistical attributes that can be derived from this database. At the general carbonates level, these reference databases demonstrate that the reservoir complexity hidden in the shadow of "heterogeneity" is actually the prevalence and statistical distribution of these multimodal pore systems and their attributes.