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Abstract The Río Neuquén field is located thirteen miles north west of Neuquén city, between Neuquén and Río Negro provinces, Argentina. Historically it has been a conventional oil producer, but some years ago it was converted to a tight gas producer targeting deeper reservoirs. The targeted geological formations are Lajas, which is already a known tight gas producer in the Neuquén basin, and the less known overlaying Punta Rosada formation, which is the main objective of the current work. Punta Rosada presents a diverse lithology, including shaly intervals separating multiple stacked reservoirs that grade from fine-grained sandstones to conglomerates. The reservoir pressure can change from the normal hydrostatic gradient to up to 50% of overpressure, there is little evidence of movable water. The key well in this study has a comprehensive set of open hole logs, including NMR and pulsed-neutron spectroscopy data, and it is supported by a full core study over a 597ft section in Punta Rosada. Additionally, data from several offset wells were used, containing sidewall cores and complete sets of electrical logs. This allowed to develop rock-calibrated mineral models, adjusting the clay volume with X-ray diffraction data, porosity and permeability with confined core measurements, and link the logs interpretation to dominant pore throat radius models from MICP Purcell tests at 60,000 psi. Several water saturation models were tested attempting to adjust the irreducible water saturation with NMR and Purcell tests at reservoir conditions. As a result, three hydraulic units were defined and characterized, identifying a strong correlation with lithofacies observed in cores and image logs. A cluster analysis model allowed the propagation of the facies to the rest of the wells (50). Finally, lithofacies were distributed in a full-field 3D model, guided by an elastic seismic inversion. In the main key well, in addition to the open hole logs and core data, a cased hole pulsed neutron log (PNL) was also acquired , which was used to develop algorithms to generate synthetic pseudo open hole logs such as bulk density and resistivity, integrated with the spectroscopy mineralogical information and other PNL data to perform the petrophysical evaluation. This enables the option to evaluate wells in contingency situations where open hole logs are not possible or are too risky, and also in planned situations to replace the open hole data in infill wells, saving considerable drilling rig time to reduce costs during this field development phase. Additionally, the calibrated cased hole model can be used in old wells already drilled and cased in the Punta Rosada formation. This paper explores the integration of different core and log measurements and explains the development of rock-calibrated petrophysical and rock types models for open and cased hole logs addressing the characterization challenges found in tight gas sand reservoirs. The results of this study will be crucial to optimize the development of a new producing horizon in a mature field.
The paper was presented at the SPE/DOE Unconventional Gas Recovery Symposium of the Society of Petroleum Engineers held in Pittsburgh, PA, May 16-18, 1982. The material is subject to correction PA, May 16-18, 1982. The material is subject to correction by the author. Permission to copy is restricted to an abstract of not more than 300 words. Write: 6200 N. Central Expwy., Dallas, TX 75206.
Reliable evaluation of hydrocarbon resources encountered in shaly clastic reservoirs of low porosity and low permeability is an important although difficult task. Log-derived estimates of the volume, type and distribution modes of various clay minerals, determination of cation exchange capacity (CEC) and Qv (CEC per unit of total pore volume), and properly selected water saturation calculation models assist formation evaluation. Since shaly clastic reservoir rocks require extensive core sampling for CEC and Qv analysis, which is tedious, time consuming, and expensive, attempts have been made to correlate such CEC and Qv data with one specific or a combination of several well logging measurements. The latter include the spontaneous potential, gamma ray, natural gamma ray spectral data, dielectric constant and acoustic-, density- and/or neutron-derived porosity, etc. Constraints associated with these concepts will be reviewed. Discussed in this paper, is an innovative digital shaly sand evaluation approach (CLASS), which provides information on total and effective reservoir porosity, total and effective fluid distribution based on the Waxman-Smits equation, reservoir productivity, silt volume, and volumes, types and distribution modes of clay minerals present in subsurface formations. Both basic concepts and field case examples will illustrate this method.
Clay minerals, used as a rock and particle term, describe an earthy, fine-grained, natural material which develops plasticity when mixed with a small amount of water. Such clay minerals significantly affect important reservoir properties such as porosity, water saturation, and permeability. Clay minerals are composed of small crystalline particles which are classified according to their crystal particles which are classified according to their crystal structure. Important ones of interest to the petroleum engineer and geologist are kaolinite, montmorillonite, illite, chlorite, and mixed-layer minerals. They are essentially layered hydrous aluminum silicates which may contain small amounts of alkalies and alkaline earths and have some substitution of aluminum by other cations, such as magnesium, iron, etc. The most common clay minerals, their composition, matrix density, hydrogen index, CEC, and distribution of potassium, thorium, and uranium based on natural gamma ray spectral information are listed in Table 1. Numerous experimental data show that the CEC value of clays is directly related to their capacity to absorb and hold water. Clays of the montmorillonite (smectite) group have the greatest capacity to absorb water and also the highest CEC values. Kaolinite and chlorite have very low CEC, and their capacity to hold water is also low. Shales can be defined as an earthy, fine-grained, sedimentary rock with a specific laminated character. Based on the analyses of 10,000 shales Yaalon describes the mineral composition of the average shale as follows: clay minerals (predominantly illite), 59%; quartz and chert, 20%; feldspar, 81%; carbonates, 71%; iron oxides, 30%; organic materials, 1%; others, 2%. Generally speaking, illite appears to be the dominant clay mineral in most of the shales investigated. Chlorite mica is frequently present, smectite is a common component in Mesozoic and younger shales, and kaolinite usually occurs in small amounts only. Therefore, a typical shaly clastic reservoir rock and/or a typical shale formation may consist of several components. Hence, no universal shale parameter can be used to characterize a specific type of argillaceous sediment or rock.
ABSTRACT The exploratory projects of hydrocarbons in the Parnaíba Basin have primarily targeted Poti and Cabeças Formations. With the rich geological knowledge obtained from the drilling of wells, the Longá Formation is viewed as a potential new exploratory play. This formation, which some studies reckon that can act as seal or source-rock, is characterized by the intercalation of shales, siltstones, and sandstones. During the drilling of a well, with the subsequent detection of gas, three 18 m long whole-cores were extracted for geological and petrophysical studies. In addition, a complete set of conventional and nuclear magnetic resonance (NMR) logs were obtained along with laboratory analyses of routine core analysis (RCA), capillary pressure, NMR, X-ray diffraction (XRD), and rock mechanics, for a complete petrophysical evaluation. The Longá reservoir is a complex reservoir with millimeter-thick laminations and reservoir layers with conductive minerals that suppress the resistivity curve. As a result, the log data had to be integrated with core data and ultimately a Domain-Transfer analysis model in uncored wells to correctly estimate petrophysical properties and make development decisions. The integration of core-log data made it possible to obtain important information about the depositional environment, lithology, reservoir characterization, calibration of the main petrophysical parameters, and mechanical properties of rocks , which can help realize hydraulic fracturing, thereby contributing to production optimization and risk reduction in exploratory projects. The productivity of the well increased by approximately 500% after stimulation of reservoir. Furthermore, the subsequent drilling of a few more exploratory wells revealed the first commercial field of the Longá Formation in the Parnaíba Basin. INTRODUCTION Petrophysical evaluation of thinly laminated reservoirs presents great complexity, especially regarding the estimation of hydrocarbon volume in place. Conventional well logging tools have a vertical resolution, which is larger than the size of the laminations in thinly laminated reservoirs, and thus fail to solve the petrophysical properties of these small layers. In addition, the presence of clay minerals generates an excess conductivity that affects the resistivity curve. The above- mentioned effects are known well in the petrophysical technical literature as complicating factors for the generation of reliable models. Additionally, this case study presents a greater difficulty due to the presence of complex mineralogy that contains metallic, heavy, and conductive minerals, thereby corroborating the need for complementary studies on core-log integration as a way of calibration of the main petrophysical parameters. Geology is strongly related to the in situ measurements performed by well logs, and thus helps in deeply understanding the spatial distribution of petrophysical properties and geometry of the different lithologies. Given the type of reservoir that this work presents, special emphasis will be given to understanding the relationship between geology and petrophysics.