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Ideally, an artificial-lift system should be chosen and designed during the initial planning phase of an oil field. However, in the haste to get a field on production, artificial lift may not be considered until after other production facilities are designed and installed. It is difficult to choose and install the optimum artificial-lift system after the surface production facilities have been installed. This is especially true in the case of gas lift. Figure 1.6-A graphical design for a continuous-flow gas lift installation based on 800-psig injection-gas pressure (light lines) overlaying a design for 1,400-psig injection-gas pressure. Figure 1.9-Simplified flow diagram of a closed rotative gas lift system. The location of surface production facilities can greatly impact the efficiency of a gas lift operation. Production stations that provide liquid and gas separation along with other gathering facilities should be located as near the wells as practical. Every effort should be made ...
Formation damage can significantly defer hydrocarbon production. Formation damage is one of the key parameters to evaluate the quality of various operations during the life of a well. The evolution of formation damage over the long run is rarely studied. This paper will present a new model of time dependent skin factor measurement. Multiple field examples are analyzed and modelled comparatively to evaluate the magnitude of the time-lapse formation damage for specific reservoir rocks.
Several mathematical models have been developed to model formation damage mechanisms. However, it is cumbersome to isolate and individually compute the contributing mechanisms of actual damage. Formation damage is a combined effect of the pore size distribution, fines migration, fluid compatibility problems, wettability, presence of inorganic salts deposition, insufficient well clean up, organic substance deposition, multiphase flow effects, etc. The proposed innovative approach utilizes the skin factor in pressure transient analysis to measure the time-lapse evolution of formation damage. The methodology has been applied to various reservoir rocks to quantify the impact for a specific rock type.
This paper will present an innovative technique and methodology to quantify the formation damage that has been materialized during the life of a well, from drilling to production. A robust technique to quantify the total damage is the computation of the skin factor from pressure transient tests conducted at various times. Observations confirm that there is a mathematical relation between the formation damage, type of drilling and completion fluid, formation rock type, and exposure time. Pressure transient tests conducted after drilling, casing, and perforating were analyzed. These initial pressure transient test results were compared with production tests performed years after drilling. Various field examples from North African reservoir rocks are presented to depict the applicability of the time-lapse method to quantify the formation damage for a given specific reservoir rock. Remedial stimulation work has been performed in such damaged wells. Formation damage could be removed, and the productivity has been revamped. The stimulation procedure has been based on core plug tests of various stimulation fluids. Potential stimulation strategies to remove or minimize formation damage are also discussed in this paper.
In this paper a new methodology and mathematical relation have been described to quantify the time-lapse formation damage mechanisms. Field examples from North African reservoirs have been depicted. The findings could be easily utilized to apply the time-lapse methodology for similar reservoir rocks in other parts of the globe to measure and quantify the magnitude of the formation damage.
Petroleum wells producing water are likely to develop deposits of inorganic scales that may form near the wellbore and may plug perforations, coat casing, production tubulars, valves, deteriorate pump performance, and affect downhole completion equipment. Scales form and precipitate because the solution equilibrium of water is disturbed by pressure and temperature changes, dissolved gases or incompatibility between mixing waters. If scale formation and precipitation are allowed to proceed, scaling will limit production, eventually requiring abandonment of the well. In order to remove the effects of scale on production after a well undergoes sharp or early decline in production, it is essential to first determine which scales are forming and where they are forming. Some of this information can be reliably inferred from computer simulation procedures or by running calipers down the wellbore and measure decreases in the tubing inner diameter so that the scale can be physically detected. Gamma ray log interpretation may also be used to detect barium sulfate scale because naturally radioactive radium precipitates as an insoluble sulfate with this scale. Scale remediation techniques must be quick and nondamaging to the wellbore, tubing, and the reservoir. If the scale is in the wellbore, it can be removed mechanically or dissolved chemically. Selecting the best scale-removal technique for a particular well depends on knowing the type and quantity of scale, its physical composition, and its texture. Mechanical methods such as Dynamic Underbalance Pressure (DUP) technique are among the promising methods of scale removal in tubulars and across perforations. The purpose of this work is to present a case study of removing barium sulfate (BaSO4) scales from perforation tunnels utilizing dynamic underbalance technique. Wells from a North African oil field were selected for designed and optimized dynamic underbalance treatments to remove barium sulfate scales that precipitated in the perforation tunnels, preventing hydrocarbons flow from the formation to the production tubing. Gamma ray log and production logging tool were used before the treatment to detect and evaluate the type of scale and the intervals affected. Then the same tools were used after the treatment to assess stimulation taking place in the wells. Data obtained from the treatment was used to develop a model for predicting productivity index/inflow performance relationships. The dynamic underbalance technique successfully removed scale from all targeted wells, leading to an increase in oil production, without killing them (i.e. while still in production). Some wells achieved increase in oil production after the treatment of up to 65%. A predictive model was developed in order to estimate the performance of an underbalance scale removal treatment.
Nasreldin, Gaisoni (Schlumberger) | Gibrata, Muhammad A. (Dragon Oil) | Rajaiah, Nanthakumar (Schlumberger) | Elsadany, Karim (Schlumberger) | Subbiah, Surej Kumar (Schlumberger) | Mukherjee, Anubrati (Schlumberger) | Eid, Tarek (Dragon Oil) | Eldali, M. A. (Dragon Oil) | Skelhorn, Richard (Dragon Oil) | Rouis, Lamia (Dragon Oil) | Oweni, Tarek (Dragon Oil) | Knispel, Ricarda (Dragon Oil) | Aly, Omar (Schlumberger) | Yousif, Mohamed Baqer Al Asadi (Schlumberger)
The oil field stacked sandstone reservoirs of the South Caspian basin in Turkmenistan are currently undergoing further field development—with the addition of deviated wells. The localized depletion occurring in some of the offshore fields in this area has thus far triggered a host of geomechanics-related challenges—including wellbore instabilities and poor hole quality. In anticipation of further depletion over the remaining fields life, geomechanics effects will become more pronounced and the associated technical and economic challenges facing these fields may increase.
To assist in future well planning and field development, and to diagnose the problems already encountered in the existing vertical wells, 3D seismic-driven mechanical earth models (MEMs) were built. These covered the main sandstone reservoirs as well as the shaley formations. This integration of data from drilling operations, open hole logs, core, seismic and formation pressure measurements provided a constrained and consistent description of the prevailing in-situ state of stress, pore pressures and rock mechanical properties. These geomechanical models were further improved by accounting for historical depletion in the fields considered. The depletion modelling was performed numerically—using a simulator performing finite difference fluid-flow calculations. The results obtained and understanding gained were then considered in the analyses of wellbore stability for future wells.
This paper describes these geomechanical analyses and modelling—including the data integration to assess wellbore stability at the current level of depletion.
Recent studies have indicated that Huff-n-Puff (HNP) gas injection has the potential to recover an additional 30-70% oil from multi-fractured horizontal wells in shale reservoirs. Nonetheless, this technique is very sensitive to production constraints and is impacted by uncertainty related to measurement quality (particularly frequency and resolution), and lack of constraining data. In this paper, a Bayesian workflow is provided to optimize the HNP process under uncertainty using a Duvernay shale well as an example.
Compositional simulations are conducted which incorporate a tuned PVT model and a set of measured cyclic injection/compaction pressure-sensitive permeability data. Markov chain Monte Carlo (McMC) is used to estimate the posterior distributions of the model uncertain variables by matching the primary production data. The McMC process is accelerated by employing an accurate proxy model (kriging) which is updated using a highly adaptive sampling algorithm. Gaussian Processes are then used to optimize the HNP control variables by maximizing the lower confidence interval (μ-σ) of cumulative oil production (after 10 years) across a fixed ensemble of uncertain variables sampled from posterior distributions.
The uncertain variable space includes several parameters representing reservoir and fracture properties. The posterior distributions for some parameters, such as primary fracture permeability and effective half-length, are narrower, while wider distributions are obtained for other parameters. The results indicate that the impact of uncertain variables on HNP performance is nonlinear. Some uncertain variables (such as molecular diffusion) that do not show strong sensitivity during the primary production strongly impact gas injection HNP performance. The results of optimization under uncertainty confirm that the lower confidence interval of cumulative oil production can be maximized by an injection time of around 1.5 months, a production time of around 2.5 months, and very short soaking times. In addition, a maximum injection rate and a flowing bottomhole pressure around the bubble point are required to ensure maximum incremental recovery. Analysis of the objective function surface highlights some other sets of production constraints with competitive results. Finally, the optimal set of production constraints, in combination with an ensemble of uncertain variables, results in a median HNP cumulative oil production that is 30% greater than that for primary production.
The application of a Bayesian framework for optimizing the HNP performance in a real shale reservoir is introduced for the first time. This work provides practical guidelines for the efficient application of advanced machine learning techniques for optimization under uncertainty, resulting in better decision making.
The hydraulic communication among 16 offshore fields located in North Africa has been investigated by means of a 3D regional dynamic model, the first ever developed for this region by Eni.
Since 1976, the area has been drilled with more than 150 wells and field pressures were found to be supported by a unique aquifer. Among these fields, two giant structures have already been put in production, the Alpha structure in 1988 and the Beta structure in 2005, whilst other minor accumulations have not yet been exploited.
Starting from a detailed field data analysis, a common pressure trend in the aquifer zone was recognized, while for each mineralized structure different hydrocarbon contacts were identified. Moreover, appraisal wells drilled in the undeveloped fields, after the production start-up of the first producing reservoir, clearly showed that depletion was occurring also in the virgin structures, thus confirming the presence of hydraulic communication.
A 90×90 km2 model is therefore developed in order to describe the overall fluids behaviour inside the region by taking into account 16 different mineralized culminations and the water bearing areas among them. Despite the complexity of the work, the model is developed and tested to be robust and to provide key information useful for determining the best possible exploitation strategies.
Exploitation of oil & gas resources is strictly related to pressure regime in a reservoir. In particular, considering reservoirs with the same petrophysical characteristics, more the reservoir is depleted, more challenging is the exploitation of hydrocarbons. The application of IOR techniques or the presence of natural aquifers support, if any, may reduce the pressure drop. The size of these pressure-supporting aquifers and their strength can vary considerably worldwide and unique regional aquifers can simultaneously affect multiple reservoirs.
Very few examples in literature are present [1, 2, 3] regarding the analyses of the impact of regional aquifer support on producing reservoirs and nearby accumulations.
A regional 3D dynamic model was built by Eni to simulate the behaviour of undeveloped fields communicating with producing pools by a unique aquifer; this model allows to optimise the development plan and to mitigate the associated risk.
Moghadasi, L. (Eni SpA) | Pisicchio, P. (Eni SpA) | Bartosek, M. (Eni SpA) | Braccalenti, E. (Eni SpA) | Albonico, P. (Eni SpA) | Moroni, I. (Eni SpA) | Veschi, R. (Eni SpA) | Masserano, F. (Eni SpA) | Scagliotti, S. (Eni SpA) | Del Gaudio, L. (Eni SpA) | De Simoni, M. (Eni SpA)
Low Salinity water and Polymer injection are as two well known Enhanced Oil Recovery (EOR) technologies. The concept of Low Salinity Water (LSW) flooding has been documented as a promising water-based enhanced oil recovery method. In the same way, many experimental studies have been proven the effect of Low Salinity Water injection to increase oil recovery by mobilizing the residual oil saturation. So far, the two methods have been deeply studied and tested singularly and their effectiveness in oil recovery has been demonstrated but the synergy between these two techniques is still not clear and needs more investigation. This study presents experimental investigations of the potential effect by injection of Polymer in combination with Low Salinity in the terms of oil recovery in a sandstone reservoir.
In this work, we report core-flooding experiments carried out on mixed-wet sandstone core plugs to investigate the efficiency of Low Salinity, Polymer and Low Salinity Polymer (LSP) flooding. The core samples were aged with a crude reservoir oil at 76°C and 90°C for around four weeks before the tests.
This EOR combination resulted to enhance recovery efficiency compared to apply Low Salinity or Polymer flooding separately. Consequently, in addition to incremental oil recovery as outcome of this synergy, the use of Low Salinity Polymer (LSP) flooding with respect to Polymer flooding demonstrated significant benefits in the terms of considerably lower amount of polymer required to make the solution therefore leading to cost reduction.
Combined injection of Polymer and Low Salinity can be implemented to enhance oil recovery in favorable conditions. The reducing the polymer amount is proven an important factor for full field application. Therefore, the synergy effect of these EOR techniques will have valuable potential for full field development strategies.
Naturally, reservoirs produce hydrocarbons to maximum of 20 % of total oil/gas in place. This means that further production will only be possible through an Enhanced Oil Recovery (EOR) strategy.
Troudi, Habib (OMV Tunesien Production GmbH) | Chevalier, Francis (OMV Tunesien Production GmbH) | Alouani, Wael (OMV Tunesien Production GmbH) | Mzoughi, Wala (OMV Tunesien Production GmbH) | Abdelkader, Omri (OMV Tunesien Production GmbH)
In Tunisian Ghadames sag basin, a significant portion of natural gas resources are looked within low permeability Ordovician sandstones deposited immediately below the Early Silurian Tannezuft world-class source rock.
The objective of this study was to develop an integrated approach to better estimate the amount of gas stored in this emerging play via the analysis of four fundamental elements: 1) the thermal maturity of the Silurian ‘hot shales’ source rock, 2) the trapping mechanism and the architecture of Upper Ordovician paleo-valleys, 3) the impact of diagenesis-lithofacies association on petrophysical properties, and 4) the fracture distribution/density and their contribution in the production.
The Early Silurian hot shales constitute the essential ingredient for the development of a pervasive gas accumulation play. The gas generated at the deeper part of the basin has charged the underlying Ordovician low-permeability sandstones mainly through complex faults system inherited from the basement. During hydrocarbon maturation and charging, pore pressure increases at rates that exceed the normal gradients, leading to local over-pressure as seen in several wells drilled down to the Ordovician reservoirs. Lateral migration via regional faults is confirmed by numerous discoveries at the edges of the basin far away from the gas kitchen.
Besides the structural closures accumulations, more complex structural/stratigraphic or purely stratigraphic traps are deemed within the Late Ordovician, and documented for instance by the development of incised paleovalleys filled with multiple fluvio-glacial and marine clastic sediments (i.e Algeria, Libya). The discovery of hydrocarbon pay zones outside of structural closures and the result of the long term tests confirm this hypothesis.
Based on seismic data it is generally very hard to recognize the paleorelief marking the base of the Late Ordovician sequence. Key elements from core studies, regional correlations, isochore maps and sequence stratigraphy have been combined accordingly, leading to a conceptual model within the observed framework. It is then possible to identify the multiple incision surfaces associated with reservoirs of Jeffara and M'Krata Formations.
The reservoir quality is considered as a major risk in deep areas (>4 km). Although, the primary pores space have been occluded by quartz overgrowths and clay cementation or lost by lithostatic compaction. The substantial gas rates observed in several wells drilled in the junction of NE-SW and NS fault trends constitute an evidence of the contribution of open fracture into the flow.
This new insight into this play has been used by OMV to identify in Ghadames basin the area with possible "Tunnel Valley features", analogues to those drilled in Libya Murzuk basin (
Polymer flooding is a mature Enhanced Oil Recovery process which is used worldwide in many large- scale field expansions. Encouraged by these positive results, operators are still looking at applying the process in new fields even in the context of low oil prices and are evaluating its feasibility in more challenging reservoir conditions: high salinity, high hardness and high temperature. Several solutions have been proposed to overcome the limitations of the conventional hydrolyzed polyacrylamide (HPAM) in these types of challenging environments: biopolymers such as xanthan or scleroglucan, associative polymers, or co- or ter-polymers combining acrylamide with monomers such as ATBS or NVP. Each of these solutions has its advantages and disadvantages, which are not always clear for practicing engineers. Moreover, it is always interesting to study past field experience to confront theory with practice. This is what this paper proposes to do.
The paper will first review the limits of conventional HPAM and other polymers that have been proposed for more challenging reservoir conditions. But more than that, it will focus on the field experience with each of these products to establish some practical guidelines for the selection of polymers depending on the reservoir and fluid characteristics.
One first result of this review is that the limits of conventional HPAM may not be as low as usually expected. Biopolymers appear very sensitive to biodegradation and their success in the field has been limited. Associative polymers appear better suited to near-wellbore conformance control than to displacement processes and some of the new co and ter-polymers are currently being field tested with some measure of success. It appears that the main challenge lies with high temperature rather than high salinity; some field projects are currently ongoing in high salinity (200 g/L) and hardness.
The paper will help set the current limits for polymer flooding in terms of temperature, salinity and hardness based on laboratory work and field experience. This will prove a useful guide for practicing engineers looking to pilot polymer injection in challenging reservoir conditions.
Gas condensate reservoirs constitute a significant portion of global hydrocarbon reserves. In these reservoirs, liquids develop in the pore space once bottomhole pressure falls below dew point. This results in the formation of a liquid bank near the wellbore region which decreases gas mobility, which then reduces gas inflow. In such complex reservoirs, it is important to correctly describe PVT impacts, adjustments to well test analysis and inflow performance, and then combine all effects in the reservoir analysis. The literature contains many references to individual adjustments of PVT analysis, well testing, or inflow performance for gas condensate reservoirs, but few studies demonstrate the complete workflow for reservoir evaluation and production forecasting in gas condensate fields. This research uses a field case study to demonstrate an integrated workflow for forecasting well deliverability in a gas condensate field in North Africa.
The workflow incorporates a description of the retrograde behavior that impact the well deliverability. The workflow begins with the interpretation of open-hole log data to identify the production interval net pay and to estimate petrophysical properties. A compositional model is developed and matched to actual reservoir fluids. Several gas condensate correlations are used to obtain the gas deviation factor and gas viscosity in order to count the change in gas properties with respect to pressure. Transient pressure analysis is described and used to identify reservoir properties. Inflow performance relationships (IPRs) are analyzed using three types of back pressure equations. The workflow integrates all data in a numerical simulation model, which includes the effect of bottom water drive.
Results show that in this field case study, reservoir behavior is composite radial flow with three regions of infinite acting radial flow (IARF). Using compositional simulation, it is found that the fluid sample for this field is a lean gas condensate since the liquid drop-out represented 1% of the maximum liquid drop-out. In addition, liquid drop-out increases by 0.1% for every 340 psi drop in reservoir pressure, which reduces the AOF by 3.4%.
The results provided in this case study demonstrate the importance of an integrated workflow in predicting future well performance in gas condensate fields. The study demonstrates how to implement the workflow in managing or developing these types of reservoirs.