A few horizontal wells were drilled in Kuwait, heavy oil field, as a part of cold production testing. Various workover interventions were performed on these wells. However, some of the wells showed sharp production decline and were producing below expectations. It was suspected that formation damage may have occurred in these ultra-low reservoir pressure wellbores due to the overbalance of the fluids used during interventions.
Concentric coiled tubing (CCT) technology comprising of a downhole jet pump, was recently employed for the first time in Kuwait and was determined to be an effective method to clean the horizontal sections and investigate the reasons for the production problems. The single phase cleanout fluid is circulated down the inner string to power the jet pump, creating a localized drawdown that vacuums the formation solids or fluids out of the wellbore and the combined sand/fluid stream returns via the CCT annulus. The multiple operating modes provided the benefit of cleaning and treating the wellbore in the same run.
This specialized system was successfully utilized to remove sand, evaluate the formation damage and enhance production; meeting all objectives in a single well intervention. Pressure and temperature gauges run below the tool on two wells recorded bottomhole pressure of only 150 psi. Post-production results has pushed the boundaries of the well interventions in heavy oil field in Kuwait and has unlocked several wellbore cleanout and formation damage evaluation opportunities using the CCT technology.
This paper reviews the benefits of the concentric coiled tubing technology and provides a comprehensive case study of the first three horizontal wells. The analysis of the sand and fluid influx profiles obtained during the vacuuming process assisted in to evaluating well production provided crucial data in formulating a management strategy.
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.
Rodriguez, Inti (Petrolera RN LTD.) | Hernandez, Edgar (Petrolera RN LTD.) | Velasquez, Richard (Petrolera RN LTD.) | Fernandez, Johanna (Petrolera RN LTD.) | Yegres, Frandith (Petromonagas) | Martínez, Rosana (Petromonagas) | Contreras, Ronald (Petrolera RN LTD.) | Korabelnikov, Alexander (Petrolera RN LTD.)
The Morichal reservoir at the Cerro Negro Extra Heavy Oil Field (Petromonagas JV) is starting its mature development phase after more than 18 years of production. In order to improve the current recovery factor which is around a value of 3%, maintain the production and reduce operational costs, two different strategies were defined: First, the use of the Jobo Member (overlaying sand deposits) to dispose the wastewater produced from the Morichal reservoir and second, the use of the shallow aquifer deposits of Las Piedras Formation as a water source for future massive implementation of EOR projects (Polymer and steam flooding), evaluating the potential origin of this water based on its physical and chemical properties. Both geological units are part of the drilled stratigraphic column of The Cerro Negro field, what brings technical and economical advantages such as high density of geological information available and the reuse of abandoned wells. This paper aims to describe the study case of the Cerro Negro Oil Field where on one hand, a static and dynamic characterization of Jobo Member was carried out in order to define the potential areas to be used as a wastewater disposal of the Morichal Member production. Based on the geological characterization, dynamic evaluation and surface facilities analysis, it was selected as the best area to dispose of more than 35,000 B/D of water derived from the production of 330 horizontal wells drilled; as well as, support the strategy of producing wells with high water cuts in zones of perched water and close to water contacts, where an important volume of oil is located which until now has been bypassed. On the other hand, the aquifer characterization of Las Piedras has allowed us to define the volume and composition of water available to use as a secure and probed water source during the EOR project implementation.
Wells in the South Ratqa field often fill with sand. Ultra low bottom-hole pressure did not allow efficient sand cleanouts in several wells. Despite using massive amounts of nitrogen during clean out, and largest available CT size (2.375") to ensure enough annular velocity; severe fluid losses occurred into the formation, which resulted in decreased well production post clean outs, moreover handling energized returns has always been a logistic and safety hazard Recently, concentric coiled tubing (CCT) technology was employed for the first time in Kuwait and five wells were identified as viable fill cleanout candidates for which traditional cleanout methods had proved inefficient at best and many times unsuccessful. The system uses concentric coiled tubing and a special vacuum tool designed to apply a localized drawdown, which would deliver the sand particles through the Coiled Tubing / Coiled tubing annulus to surface. Returns were handled using H2S resistant lines into a desander. A carefully engineered cleanout program enabled removal of more than 12 MT of sand from four vertical wells, and also identified the formation damage in a horizontal wellbore. The identification of wellbore damage revealed the best intervention to cure the damage and eliminated speculative remedies that sometimes increased the damage done to reservoir. Additionally, the layout of well plots was designed in a very congested way to maximize output but made it impractical to have return pits, requiring mobile tanks to handle returns, while the energized nature of returns in conventional nitrogen jobs are dangerous to handle in a closed tank environment. CCT eliminated that hazard as the returns are not energized.
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.
Telles, J. (Schlumberger) | Rojas, L. (Schlumberger) | Díaz, L. (Schlumberger) | Atencio, N. (Schlumberger) | Cortés, A. (Schlumberger) | Calderón, E. (Schlumberger) | Dorca, J. (Schlumberger) | Peñaranda, J. (Schlumberger) | Navarro, V. (Schlumberger) | Ydrogo, C. (PDVSA) | Mata, L. (PDVSA) | Correa, E. (PDVSA) | Páez, D. (PDVSA)
Accretion is a common phenomenon that affects drilling operations in the Orinoco Heavy Oil Belt. The main reservoir, where most horizontal sections are drilled, is the Oficina Formation. Accretion negatively impairs operational efficiency, thus generating stuck pipe incidents, problems while tripping due to high torque and drag values related to friction factors, and the unrecommended backreaming operations. In addition, accretion causes excessive fluid surface losses linked to plugged shakers screens. This document shows the laboratory tests and successful field results obtained from the combination of specialized surfactant and lubricant agents working in synergy to reduce the accretion effect. The laboratory test demonstrated the synergy between the lubricant and surfactant in different tests, such as lubricity, accretion, and permeability damage testing. In the field, positive results were achieved in nine horizontal wells, thus increasing operative efficiency by reducing stuck pipe incidents, backreaming operations, and unplanned trips. This impact over flat times was also accompanied by a fluid waste reduction that improved the shakers' screen usage and reduced the amount of oil coating the cuttings, which facilitated the treatment process and minimized environmental impact.
It is estimated that 70% of the world's oil and gas reserves are contained in reservoirs where sand production is or will become, a problem during the life of the field (
This study presents some results of a developed sand prediction model that has been used in Venezuela to understand sand transport characteristics in heavy oil and to estimate suspension and deposit critical velocities. In addition, results are presented of a sensitivity analysis of particle diameter and water cut carried out using a dynamic multiphase flow simulator to determine the accumulated solids content in some pipelines that helped to develop adequate cleanup procedures.
Pressure/volume/temperature (PVT) analyses were initially conducted in order to to reproduce the field characteristics of the produced fluid, including diluted fluid. Sensitivity studies were done to evaluate the effects of some parameters, such as grain size, flow rate, and water cut, to determine how they affect critical transport velocities. From these studies, the volume of particles deposited and the thicknesses of these deposits were determined, which helped the operator to define appropriate pigging program to remove sediments and to estimate the effect on the production system without an appropriate cleanup activity.
The initial result shows that the network gathering system operates below deposition critical velocity, however, a stationary sand bed is growing in pipelines near the wells.
In addition, the parametric studies revealed that when the particle sizes increase, the critical velocities increase. Besides that, critical velocity shows different behavior with water cut. Critical velocity increases when the water cut goes from 0% to 5%, but if this maximum value is overcome, the critical velocities decrease. Field data indicated that the amount of material received at the end of the system (CPF) during 500 days is 1600 tons of sand, but the maximum operation allowable pressure is reached 290 days after starting up the oil production. Dynamic flow simulations indicated that it is necessary to start the cleaning operation between 150 and 290 days after the start of production, depending on the available pressure to push the pig.
This paper summarizes the novel contribution of using dynamic flow simulations for sand prediction and a control model in one of the growing joint venture companies in FAJA PetroIndependencia in Venezuela.
Prediction of critical flow rate to prevent sand settling is important for flowlines that are in the design stage. This paper offers a valid approach to extend the predicted sand critical velocities to other fields in FAJA with similar crude conditions to aid in pipeline design.
Nor has it been the purpose of the discussion presented thus far to provide explicit formulas for predicting quantitatively the recoveries from specific reservoirs or for evaluating them as items for sale or purchase. It has been an aim of this work to provide an exposition of the physical principles underlying the behavior of oil reservoirs so as to permit an understanding of their performance when observed in practice and an anticipation of the broad features of their performance from the consideration of basic data gathered during their development.
Society of Petroleum Engineers - Copyright transferred to SPE by Robert Muskat on behalf of Morris Muskat.
Past studies have shown that use of diluent injection with ESPs can be an efficient artificial lift method for heavy oil fields. It consists of injecting a light hydrocarbon liquid to reduce the oil density and viscosity. This paper describes an integrated modeling solution designed to maximize the reservoir oil production while minimizing the diluent requirement and keeping the crude oil quality within technical and marketing specifications. The field studied is an offshore heavy oil asset. It consists of two reservoirs with API gravities of 14 and 12, and oil viscosities at reservoir conditions of 70 cp and 500 cp. The field includes some 60 production wells.
Diluent can be injected (1) in each individual well at the ESP and (2) in the surface processing facility prior to the second stage separator. Operating constraints include (1) minimum wellhead pressure, (2) diluent availability, (3) final crude quality specifications, (4) maximum field oil and liquid production rate. The difficulty of the production optimization problem lies in the nonlinearity of the well production curves and viscosity model. In this paper, we develop a Mixed Integer Linear Programming (MILP) formulation by piecewise linearizing the nonlinear behaviors. For each well at each time step, we adjust the black-oil rates from a reservoir simulator to create piecewise linear well performance curves giving the reservoir oil production as a function of diluent injected at the ESP.
The proposed integrated solution is used for the entire production life of the field, which is still in the development phase. The solution is coupled with a reservoir simulator (1) to determine optimal diluent requirements over time, (2) forecast field production of reservoir oil, diluent, water and gas, and (3) foresee eventual bottlenecks in the infrastructure design (e.g. limiting constraints). The proposed solution can easily be used as a Real Time Production Optimization (RTPO) tool to find the optimal operating point based on the latest measurements (or real-time data). The optimal solution ensures the highest field reservoir oil production while meeting all constraints and keeping the diluent consumption at a minimum. The increase of the field oil production rate due to optimal diluent allocation ranges from 2 to 10 %. Cumulative reservoir oil production increases by approximately 3 million std m3.
The uniqueness of the solution comes from the integration of all operating constraints into a single mathematical formulation. The computational time (1s – 10s) of the proposed solution outperforms any classical nonlinear approach. This allows running many sensitivity analyses of the entire integrated asset model.