Various methods that link a representative pore-throat size to permeability k and porosity ϕ have been proposed in the literature for rock typing (i.e., identifying different classes of rocks and petrofacies). Among them, the Winland equation has been used extensively, although when it was first proposed, it was based on experiments. Because of empiricism, the interpretation of the parameters of the Winland model and their variations from one rock sample or even one rock type to another is not clear. Therefore, the main objectives of this study are (1) to propose a new theoretical approach for identifying rock types that is based on the permeability k and the formation-resistivity factor F and (2) to provide theoretical insights into, and shed light upon, the parameters of the Winland equation, as well as those of other empirical models. We present a simple, but promising, framework and show that accurate identification of distinct petrofacies requires knowledge of the formation factor, which is measured routinely through petrophysical evaluation of porous rocks. We demonstrate that, although some rock samples might belong to the same type on the k-vs.1/F plot, they might appear scattered on the k-vs.-ϕ plot and, thus, could seemingly correspond to other types. This is because both k and F are complex functions of the porosity, whereas the porosity itself is simply a measure of the pore volume (PV), and does not provide information on the dynamically connected pores that contribute to both k and F. We also show that each rock can be represented by a characteristic pore size Λ, which is a measure of dynamically connected pores. Accurate estimates of Λ indicate that it is highly correlated with the permeability.
Lack of accurate estimation of reservoir permeability has been one of the most challenging problems for enhanced hydrocarbon recovery. Pore-structure variation in carbonate rocks caused by diagenesis controls reservoir permeability heterogeneity. In this paper, we propose a rock-physics-based method of quantitative characterization of pore structure and permeability heterogeneity using core and sonic logs. Mercury injection capillary pressure (MICP) and Leverett J-function curves can be first used to classify the pore systems and permeability variation in the reservoirs. Shear frame flexibility factor (γµ) derived from sonic logs is further used to quantify the pore type and permeability variation in the reservoir zones. In the studied Puguang gas field, different pore systems in five reservoir zones are identified: moldic, sucrosic macrointercrystalline, mixed moldic and intercrystalline, meso-intercrystalline, and micro-intercrystalline pores respectively in the upward shallowing sequence of the Early Triassic reservoir. Permeability varies significantly between the five zones. Results show that at a fixed porosity, moldic pores show higher velocity, resistivity, yet much lower permeability than intercrystalline pores. When γµ < 4, the reservoir zone is dominated by moldic pores; when 4 < γµ < 8, meso- to macro-intercrystalline pores are dominant; and when γµ > 8, micro-intercrystalline pores are prevalent. Two different permeability-porosity trends controlled by distinctive pore types are also distinguishable by γµ. Reservoirs dominated by isolated moldic pores, at a given porosity, has much lower permeability than the ones dominated by connected intercrystalline pores. The results on pore-type discrimination and permeability estimation have been successfully used to understand the production problems in the Puguang reservoir.
Jin, Fu (CNPC Research Institute of Petroleum Exploration and Development & CNPC Drilling Research Institute) | Xi, Wang (CNPC Research Institute of Petroleum Exploration and Development & CNPC Drilling Research Institute) | Shunyuan, Zhang (CNPC Drilling Research Institute)
Located in south of Eastern Venezuela Basin, Orinoco Oilfield is the unique huge ultra-tight oilfield that has not been developed by scale in the world. The high-density tight oil is known for its high content of acids, heavy metals and asphaltenes with a viscosity of 1000-10000mPa·s. ML Block whose OOIP is 178*108bbl is situated in east of the oilfield, while cluster horizontal well drilling and cold production technologies are still under research there.
Based on precise geological researches numerical simulation was carried out to optimize cold production of ultra-tight oil with foamy oil flow patterns in horizontal wells, including optimization of well placement, well spacing and horizontal section length. The near-bit geo-steering drilling technology was applied on adjacent wells to test its performance, while an experiment was conducted with PVT apparatuses to examine the effect of pressure decline rates on foamy oil flow. A long core pressure depletion test was accomplished to reveal the effect of foamy oil flow on recovery factors.
Three-dimension cluster horizontal well drilling and completion technologies shall be applied to develop ultra-tight oil reservoirs in huge loose sandstones, with the near-bit geo-steering drilling technology that controls landing points and horizontal sections in real time, keeping the bit move ahead along the lower boundary of the reservoir. Therefore, recovery rates may be dramatically improved due to the gravity drainage of ultra-tight oil. The most appropriate spacing of horizontal wells (500-600m) and horizontal section length (800-1200m) were determined to achieve the maximum recovery rate. The experiment proves that the recovery rate improves as the formation permeability increases, which means the "worm hole" contributes to heavy oil extraction. Boreholes with relatively large diameters, extensive perforated holes and slotted liners may be used to complete wells. In order to take the most advantages of the foamy oil flow mechanism high displacement ESPs shall be used with the selected thinner squeezed at the bottom, otherwise PC pumps with the thinner added at the wellhead are recommended.
Cold production technologies applied in ML Block save the overall production cost by 15.2%, improving the ultimate recovery rate by 8.6%. The foamy oil flow theory is improved, while it is the first time to integrate foamy oil flow production technologies with cluster horizontal well drilling technologies and near-bit geo-steering drilling technologies. As a result, the overall production rate of tight oil was greatly improved and the average production life of wells was extended.
Rodriguez, Ricardo (PDVSA) | Villavivencio, Elvio (PDVSA) | Bellorin, Pavel (PDVSA) | Rendon, Lerrys (PDVSA) | Orozco, Jose (Schlumberger) | Quintero, Andreina (Schlumberger) | Chapellin, Alvaro (Schlumberger) | Mutina, Albina (Schlumberger) | Bammi, Sachin (Schlumberger)
The Orinoco Oil Belt (Faja) is the largest known heavy oil reserve in the planet. Geologically, its reservoirs are composed mainly of sequences of shales and unconsolidated sands. The properties of the sand units such as shale volume, water saturation, porosity, and thickness can present lateral heterogeneity at a few hundred feet scale. The high viscosity of the oil and its variation both laterally and vertically is one of the key features of the Faja. Prediction of water saturation from resistivity can be difficult due to multiple reasons, including the low salinity of the formation water and wettability changes.
For the field development, Faja reservoirs are drilled following a specific drilling pattern called a “macolla”. A macolla is composed of a vertical stratigraphic well followed by a group of two to four highly deviated wells (slant wells). These deviated wells play a fundamental role in cluster delineation, because they are key calibration points in the trajectory planning of the subsequent set of horizontal wells, which are completed with a slotted liner to maximize production.
Usually, in Faja, only vertical stratigraphic wells include comprehensive logging suites. These suites include elemental gamma ray spectroscopy, microresistivity images, sonic, dielectric, and magnetic resonance measurements at multiple depths of investigation. Moreover, due to the complexity of logging highly deviated wells in unconsolidated formations, many slant wells are not logged or logged only for correlation (gamma ray and resistivity logs). The ability to acquire more log data in the slant wells improves reservoir description and reduces the uncertainty in the planning of horizontal production wells.
The case study presented here illustrates the value of integrating data from vertical and slant wells in a macolla cluster. Comprehensive logging suites acquired in the vertical wells are complemented with through-the-bit logging suites acquired in the slant wells. Through-the-bit technology has recently been introduced in Venezuela and has proved to enable the acquisition of high quality logs through unconsolidated sand shale sequences in highly deviated boreholes. Rig time due to the logging operation and the risk of sticking of the logging string was also reduced.
This case study presents the workflow for and the results of the multiwell data integration in which different formation properties, including lithology-based facies, are propagated and incorporated into a 3D structural model. This workflow provides critical input to reservoir characterization and facilitates significantly the planning of horizontal wells.
This paper presents the workflow and learned lessons during the construction of a fully compositional integrated subsurface/surface model for the Santa Barbara and Pirital fields, which are important oil production units located to the east of Venezuela. In this approach, the numerical reservoir simulation models, wells and surface facilities were coupled in order to obtain production profiles considering both changes in the reservoir conditions and surface restrictions, achieving an assertive planning of asset development.
The applied methodology is based on the construction of more than 150 compositional well models, performing sensitivity analysis to define multiphase flow correlations for vertical pipe and chokes. A network model, which comprises more than 900 Km of lines, 3 main flow stations, and 3 separation levels, was also built in compositional mode honoring line sizes, lengths and elevation changes. Two numerical simulation models represent the most reliable characterization of the main reservoirs. Each model was initialized and ran separately, in order to discard internal inconsistencies. Then, the integration was performed considering the sand face on the wells as the coupling point.
The integrated asset modeling allowed predicting the production behavior of the reservoirs taking into account the constraints of the surface facilities, reducing the uncertainty of forecasts and identifying limitations and bottlenecks at surface level. It was also possible to accurately determine the details of the hydrocarbons streams (NGL) at different pressure stages of the network, which reasonably matched with field data (less than 3% of difference). The result is a versatile tool for the integrated asset management, which allows to sensitize all the elements of the production chain and estimate how each one affect the performance of the asset, discarding the division between departments upstream and downstream and establishing a common management strategy for all disciplines.
The novelty of this work is based on the challenge of building fully compositional coupled models considering giants and complex reservoirs with large surface networks. The proposed methodology and learned lessons will certainly serve as reference for similar future works.
Huyapari is a giant field, located in the Orinoco Heavy Oil Belt of eastern Venezuela. Huyapari contains huge original oil in place (OOIP) of extra heavy crude oil (7 to 9°API) with excellent reservoir properties that enable primary production of the extra heavy crude oil by using long horizontal wells. Nevertheless, the live oil viscosity variation at reservoir conditions (1,500 to 20,000 cp) represents a production challenge in the field. This study aims to improve the fluid heterogeneity understanding in the field through the application of PVT (Pressure, Volume and Temperature) and geochemical analysis for oil viscosity estimation.
Fluid heterogeneity mapping using crude fingerprint analyses was performed to understand the variability of the oil biodegradation level across the field. PVT data provided reservoir GOR and supported the oil chemical variation. Biomarkers correlations were also evaluated to obtain a better estimation of oil viscosity, and then compared with oil viscosity measurements performed at surface and reservoir conditions.
The integration of geochemical analysis with the PVT data allowed to improve the Huyapari field correlations used for well potential estimation. A shallow reservoir of the field with few production wells and larger prospective areas was chosen to evaluate its oil viscosity variation and the methodology application. A better well placement and reservoir management strategy was established, thus demonstrating the value of this data integration.
This study demonstrates that reservoir geochemistry coupled with reservoir engineering data is a cost-effective reservoir management tool. This methodology could be useful for application in other extra-heavy oil fields where little reservoir geochemistry input has been considered in their field simulation procedures.
The workflow for mature-field redevelopment requires a multidisciplinary team to analyze, select, and rank well candidates for intervention and production optimization. An objective evaluation of the well's productivity and reserves is essential for identifying possible alternatives to increase production. For this study, an analysis was conducted on 152 wells from the Carito field. As the second-largest oilfield producer in the Maturin sub-basin of eastern Venezuela, the Carito field encompasses approximately 150 km2 and comprises the El Carito and Carito south reservoirs.
The Carito reservoir presents a high degree of heterogeneity resulting from complex, compressional faulting and varying sediments and includes hydrocarbons containing gas, condensate, volatile, black oils, and tar mat (oil mixed with wet sand). The Carito south reservoir behaves like a black-oil reservoir. The workflow presented in this study identified 20 candidate wells ranked by their potential to increase production. An intervention plan was then defined and ranked according to technical and economic criteria. This paper presents the successful application of this methodology in the Carito field to improve well productivity by approximately 7,000 bpd, proving that the method can be easily adapted to other areas.
Using hydrofluoric (HF) acid for the removal of clays and silica minerals impairing permeability in sandstone formations requires fluids free of sodium or potassium ions. High temperatures (> 300°F) further limit HF acid use and its effectiveness because of potentially damaging effects to the formation and its corrosivity. This paper discusses laboratory testing of an aminopolycarboxylic acid (APCA) fluid containing 1 to 1.5% HF acid and highlights its advantages and differentiating characteristics with respect to previous HF acid fluids.
Core flow testing at 360°F was conducted on outcrops of two types of sandstone representing a heterogeneous (65% quartz and illite/kaolinite with feldspars) and a clean (95% quartz) type of mineralogy. The APCA fluid containing HF acid, which incorporates a modulating agent for the HF acid-secondary reaction on aluminosilicate minerals, was compared to the pure APCA (pH 2) fluid and formic acid. Effluent analysis of the spent fluid was completed by inductively coupled plasma (ICP) optical emission spectroscopy (OES). Corrosion inhibition testing was completed for coiled tubing (CT) and carbon steel (NT-95) up to 360°F, employing various classes of inhibitors.
Using an APCA chelating agent in sandstone HF acidizing expands the temperature range of application and the type of minerals that can be exposed to such fluid. High-temperature HF acidizing is also delimited by the type of steel tubing that can be exposed to such fluid, placing significant demands on corrosion control. Laboratory results obtained in this investigation demonstrate that corrosion can be well managed for a fluid having a pH of 2.5 and HF acid concentrations of 1 to 2% from 250 to 275°F and at 300°F with a pH of 4. Testing results show that the APCA/HF fluid, having a pH of 2.5, can effectively be used to treat heterogeneous sandstone of moderate carbonate content at 360°F and is also compatible with a clean sandstone. The APCA/HF fluid stabilizes the most problematic ions in the spent fluid—Al3+, Fe2+/3+, Ca2+, and alumino-fluorides—without the need for acid preflushes and without maintaining highly acidic conditions. Comparison to formic acid and HF acid-free APCA fluid is presented.
Using aminopolycarboxylic acid-type chelants is restricted by the materials commercially available, all of which contain sodium, with one exception, which has ammonium. Hence, HF acidizing has been restricted to ammonium-containing fluids. A differentiating characteristic of the fluid reported here is its ability to sustain Na+ concentrations exceeding 1 M and K+ concentrations in excess of 0.5 M. Furthermore, it is suitable for the treatment of carbonate-laden mineralogy formations up to 360°F.
Well tests are typically used to evaluate formation damage before and after workovers. Buildup tests are the most commonly used transient because less flow rate measurement uncertainties leading in more reliable results, and they have a robust mathematical foundation. To take in account the flow rate history and its uncertainties several deconvolution algorithms were developed. These algorithms also are applicable to minimize the initial distortion in the reservoir's pressure response due to wellbore storage, with the expectation of improving the permeability and total skin estimated in shorter logging times.
This paper presents a comparative study of conventional well test methods, and direct and indirect deconvolution techniques in several field cases. This study includes buildup tests of real-time sandface rate measurements during the after-flow period. These field cases were analyzed using conventional well test methods and three deconvolution techniques; namely, straight line approximation, material balance deconvolution, and modified "ß" function.
We determined that the three deconvolution methods are preferable to conventional well test methods because they require much shorter logging times; however, their reliability depends on the real-time data acquisition quality.
The well tests analyzed show that we cannot rely solely on the new deconvolution techniques for well test interpretation in shorter times; however, these new methods improve the reliability in the main matching parameters, permeability and total skin, at no additional time and cost. As a result, the new methods are excellent additions to the techniques used for well test interpretation.
Reversing the natural process of pressure decline in hydrocarbon deposits and decreasing damage in the sandface caused by drilling, production, etc. are the most significant operator objectives for maximizing the extraction of hydrocarbon reserves. This paper discusses the successful application of cementing technologies in thermal wells to maximize the life of the well. In areas, such as the Orinoco Belt, the implementation of cyclic and continuous steam injection helps decrease oil viscosity and improves oil-relative permeability to increase production. Because conditions downhole vary dramatically, it is recommended that cement slurry designs be based on the position in the hole and the conditions to which slurries will be subjected during their lifetime. To help overcome these challenges, combinations of optimized treatment procedures and technologies were applied to wells in extreme conditions, demonstrating improved results.