Formation of sulphate and carbonate scale is well understood within the hydrocarbon extraction industry with injection of incompatible water such as seawater into reservoir with significant concentration of barium, strontium and calcium. To overcome this challenge chemical inhibition has been utilized for many decades and in the past 15 years elimination/reduction of the sulphate ion source from injection seawater using sulphate reduction membranes has been employed. This paper present laboratory work to qualify a scale inhibitor and field results of its application to prevent scale formation when an operator had to change from low sulphate seawater (LSSW) mixed with produced water (PW) for their water injection source to a blend of LSSW/PW and full sulphate seawater (SW). The increased level of sulphate presented a significant scale risk within the topside process on fluid mixing but more significantly increased the risk of scale formation within the near wellbore region of the injector wells which were under matrix injection rather than fracture flow regime. The qualification of a suitable inhibitor required assessment of the retention of a potentially suitable vinyl sulphonate co polymer scale inhibitors to ensure it had low adsorption and was able to propagate deep into the formation before being adsorbed from the supersaturated brine. Coreflood studies using reservoir core were carried out to assess the scale risk of the LSSW/PW/SW brine, propagation and release characteristic of the short-listed scale inhibitors. The recommendation that followed the laboratory studies was to apply a batch treatment of concentrated scale inhibitor to each injector well to provide a high concentration pad of scale inhibitor that would be transported into the reservoir when the scaling LSSW/PW/SW fluid was injected. Protection was provided by continuous application of the same chemical at minimum inhibitor concentration to prevent scale formation within the topside and the desorption of the batched inhibitor within the near wellbore would prevent scale formation within this critical region. Thirteen injection wells were treated with a pad of 10% vinyl sulphonate co polymer scale inhibitor to a radial distance of 3 ft.
Tahir, Muhammad (Clausthal University of Technology) | Hincapie, Rafael E. (Clausthal University of Technology) | Foedisch, Hendrik (Clausthal University of Technology) | Abdullah, Hiwa (Clausthal University of Technology) | Ganzer, Leonhard (Clausthal University of Technology)
Oil recovery using Smart Water technology (SWF) can be maximized by optimizing the composition of injected water. Brine optimization is also believed to improve Polymer Flooding (PF) performance. The present study aims to assess and define the potential impact of combining Smart Water with Polymer Flooding, based on the sulphates presence in formation/injection water and rock composition. In this work, we study the impact of sulphates (sodium sulphates) on polymer viscoelasticity and its performance in porous media, based on oil recovery and pressure response.
Brine composition is optimized after having synthetic sea water (SSW) as a base brine. Brine optimization is performed by doubling the amount of sulphates, whilst diluting (in fresh water) the SSW-brine to a tenth of its initial concentration. Thus, four brines were utilized: 1) SSW (formation water), 2) SSW but double sulphates, 3) SSW/10 and 4) Brine 2/10. The workflow included core plugs aging prior core flooding. Secondary tertiary and quaternary mode experiments were performed to evaluate the feasibility of applying both processes.
The SSW-brine optimization (a tenth of its initial concentration) resulted in a salinity of 4.2 g/L which is in good agreement with previous studies (≤5 g/L), to guarantee additional oil recovery using SWF. Polymer rheological characterization was performed over wide range of shear rates and temperatures. Sodium sulphates showed increase in polymer viscosity as compare to sodium chloride or divalent cations. Enhancement in polymer linear viscoelasticity is observed with an increase in sulphate ions concentration. Furthermore, viscosity analysis over temperature has advocated to perform the core flood experiments at 45°C. Fluids were optimized/selected using a comprehensive rheological evaluation
This study focuses on the influence of sulphates ions on SWF and PF performance for application in sandstone reservoirs. Previous studies have mainly focused the evaluation of sulphates ions impact only in carbonate reservoirs. It is of importance to further understand/clarify the effect of sulphates for field applications of SWF and PF combined. This in turn, could lead to improve the economics of project performance, by means of incremental oil and the less polymer required.
Campos, Mario C. M. M. (Petrobras) | Ribeiro, Leonardo D. (Petrobras) | Diehl, Fabio C. (Petrobras) | Moreira, Cristiano A. (Petrobras) | Bombardelli, Douglas (Petrobras) | Carelli, Alain C. (Petrobras) | Junior, Gilberto M. J. (Petrobras) | Pinto, Sergio F. (Petrobras) | Quaresma, Bernardo (PUC-Rio/Tecgraf)
It is difficult to control and to manage wells' startup in offshore platforms. In order to solve this problem an intelligent system can play an important role, since available qualitative operator and design knowledge can be easily implemented to assist the operator during wells' startup. This paper describes the integration of an expert system associated with anti-slug control for well startup. The intelligent system has many heuristic rules to implement the automation of the startup procedures, like the opening choke valve while simultaneously respecting many constraints. Severe slugging flow regimes are one of the major disturbances for the operation of offshore production platforms, and can cause many unplanned shutdowns. Therefore, it's important to combine startup intelligent system with an anti-slug advanced control module for each well. The benefits are associated to reducing possibility of unplanned shutdowns during well startup operational procedures, decreasing operators' stress and also helping to minimizing impacts to the environment. A prototype was implemented in one platform with good results for a safe and efficient wells startup procedure. This paper will present the development and results of this intelligent system for wells' startup and anti-slug control for offshore platforms.
Campos, Mario C M M (PETROBRAS/CENPES) | Lima, Marcelo L (PETROBRAS/CENPES) | Teixeira, Alex F (PETROBRAS/CENPES) | Moreira, Cristiano A. (PETROBRAS/UO-RIO) | Stender, Alberto S (PETROBRAS/UO-RIO) | Von Meien, Oscar F. (PETROBRAS/SUP) | Quaresma, Bernardo (PUC-Rio/Tecgraf)
The search for improvements in the production efficiency is one of the main challenges for the production engineers responsible for an asset, mainly at moments of low prices and very strict regulations for safety, environment and quality of products. Another point is that offshore plants are becoming more complex, so advanced control systems can support the operators and play an important role to improve stability and profitability. This paper will present an advanced control algorithm for gas-lift optimization of offshore wells that aims to increase oil production. It will also show and discuss some results of the implementations of this real time advanced control system in two offshore platforms, emphasizing the economic gains and critical points to maintain this controller running with a good performance.
ABSTRACT: This paper investigates how the cement bond behind the casing affects the sanding risk by using a numerical sand production prediction approach for cased and perforated completions. A Finite Element sand production prediction workflow was used as the basis of the model setup, which includes a three-layered model considering the rock, well, casings and perforations. Additional detail for the casing and partial cement coverage was implemented in these models to capture the changed loads, stress and boundary conditions affecting both the wellbore and perforations. Modelling considered a number of different conditions: 1) Amount of cement coverages; 2) Depletion stages; and 3) Rock strengths. The prediction results were compared with the standard sand production prediction results assuming a perfect cement bonding. It was found that for partial cement coverage, increase of plastic strain on wellbore depends on the location of the cement void: if the void is in a low stress concentration location, the risk of sanding on wellbore wall only increases slightly comparing to fully cemented cases; if the void is in a high stress concentration area then the risk of sanding will be as high as in the no cement case. Compared to the great increase in the sanding at the wellbore wall, the increase in sanding risk on the perforations is minor and mainly for perforations in high stress concentration areas. The results of the study can be used to support a selective perforation strategy based on cement bond logs to identify the casing-cement bonding conditions and the target area parameters such as rock strength and orientations.
Predicting the onset of sand production in oil and gas fields is an important aspect of sand management and has been the focus of numerous researchers over the past decades. Laboratory measurements, field calibrations, and different prediction methods including both analytical and numerical (Okland et al. 1996, van den Hoek et al. 2000, Veeken et al. 1991, Volonte et al. 2013, Willson et al. 2001) have been developed to define the conditions at which the reservoir rock will fail and start to produce sand. However, simplified and idealized assumptions were usually used in the chosen methods to get a faster solution for a larger number of cases. Although it might be fast and effective, it could also increase uncertainty for some predictions and may lead to wrong decision-making in some extreme cases. Among all the complications caused by either operations or hostile field conditions, completion integrity, such as the cement bond condition for cased and perforated completion, has been commonly neglected during sand production prediction. Borehole condition and cement sheath are sometimes considered as part of the sand management by using rule of thumb methods (Addis et al 2008), however, the effect of cement bond quality towards the risk of sand production has not been investigated properly in previously published references.
Quevedo, R. (Tecgraf Institute – Pontifical Catholic University of Rio de Janeiro (PUC-Rio)) | Ramirez, M. (Tecgraf Institute – Pontifical Catholic University of Rio de Janeiro (PUC-Rio)) | Roehl, D. (Tecgraf Institute and Department of Civil Engineering - PUC-Rio)
ABSTRACT: Variations of internal pressure within reservoirs structurally compartmentalized by sealing faults induce changes in deformations and stresses. If these changes are significant, they can create favorable conditions for fault reactivation by shear or tensile modes. In that scenario, the conditions that develop within reactivated fault zones can trigger potential geomechanical problems such as oil exudation, seismicity and loss of casing integrity. Therefore, it is necessary to forecast the geomechanical behavior of the field and establish limits for pressure changes within the reservoir. This paper deals with a methodology for the evaluation of fault reactivation and fluid migration, using 2D and 3D Finite Element models. In these models, discrete faults are introduced through zero thickness interface elements. The reactivation mechanisms and fluid migration are controlled by the Mohr-Coulomb plastification criterion. 2D and 3D geomechanical models of a field with a set of faults were built in order to compare their predictions. According to the results, different injection pressure limits can be obtained using 2D and 3D models. Furthermore, the 3D configuration of faults that intersect each other can create preferential flow paths for migration of fluids which are not observed in simplified 2D models.
Oil and gas reservoirs structurally compartmentalized by sealing geological faults are found in different fields of the world. During the production phase, the sealing of stable faults can be compromised by the strains triggered by pressure changes within the reservoir. Those strains together with the geomechanical properties and the geometrical configuration of the rocks and faults, can alter significantly the stress state. Consequently, sealing faults can become reactivated or hydraulically conductive, causing potential geomechanical problems related to exudation, casing integrity among others (Segall et al., 1994; Morton, R., 2006; Chan & Zoback, 2007).
In the literature, several approaches have been used in order to characterize and forecast fault reactivation through the establishment of limits for pressure changes within the reservoir. Most of those approaches consider critical sections through 2D models. That avoids the use of complex domains and the high computational effort that the use of a 3D model demands. This strategy has been used by several researchers: Cappa and Rutqvist (2010), Mendes et al. (2010), Rutqvist et al. (2013), Rueda (2014) and Pereira et al. (2014).
Serajian, V. (GeoMechanics Technologies) | Diessl, J. (GeoMechanics Technologies) | Bruno, M. S. (GeoMechanics Technologies) | Hermansson, L. C. (Ridge) | Hatland, J. (Ridge) | Risanger, M. (Ridge) | Torsvik, M. (Wintershall Norge A/S)
The objective is to investigate potential fault reactivation caused by high-volume injection into a North Sea well to assess the risks associated with converting a production well into a water injection well. The well is located within the Brage Field less than 100 meters from a major fault and there is concern for fault reactivation due to high volume water injection near this fault.
An integrated 3D geologic, fluid flow and geomechanical model was developed for the area of interest to evaluate fault reactivation risks. The 3D integrated models were constructed based on seismic horizon data and well logs. The 3D fluid flow model was calibrated and history matched using the pressure and temperature data from the current well and other adjacent wells. The developed 3D fluid and heat flow model was used to estimate pressure and temperature distributions adjacent to the fault after water injection in the target well. The results of the 3D fluid flow model were then imported into the 3D geomechanical model to predict the induced stresses and displacements near the injection zone and on the face of the fault.
The results of the integrated geologic, fluid flow and geomechanical models indicate that the poro-elastic stresses induced by high volume injection into the proposed well are not sufficient to induce major slip on the nearby main fault, considering a wide range of reasonable physical and material property assumptions for the fault.
The results of this study are used in specifying the maximum daily water injection rates in the proposed well without the fault reactivation concerns. With the proposed water injection rate, the sealing capacity of the major fault will be guaranteed and the injected water will be directed into the reservoir for pressurization and water flooding purposes.
Ramstad, Kari (Statoil ASA) | McCartney, Ross (Oilfield Water Services Limited) | Aarrestad, Henriette Dorthea (Statoil ASA) | Lien, Siv Kari (Statoil ASA) | Sæther, Øystein (Statoil ASA) | Johnsen, Rita Iren (Statoil ASA)
The Johan Sverdrup field will at maximum production contribute 25% of total oil production from the Norwegian continental shelf. Geochemical formation water interpretation and development of a scale management strategy have been performed to ensure high well productivity and process regularity of the field.
Uncertainty in the formation water compositions challenged the decision to inject normal seawater or low sulphate seawater into the reservoir for pressure support. Water compositions in samples obtained from appraisal wells were unusual for the Norwegian North Sea, being sulphate-rich with negligible barium. This was suspected to be an artefact of drilling fluid contamination and corrections were applied to obtain representative estimates. These confirmed that the formation waters had variable salinity (21–48 g/L chloride), and were indeed sulphate-rich (94–746 mg/L) and barium-depleted (<6 mg/L). The compositions may reflect (a) mixing of formation waters across the field over geological time and (b) interactions with the underlying Zechstein Group (anhydrite). The focus here is on issue (b), as a detailed evaluation of local/regional aquifer movements in geological time, communication patterns and flow restrictions is beyond the scope of this paper.
Three appraisal wells in the Geitungen Terrace showed barium-rich formation water outside the main reservoir area where no underlying Zechstein Group was present. Initially, there were concerns about the scaling risks associated with mixing sulphate- and barium-rich formation waters. However, present geological understanding indicates insignificant aquifer volumes with barium, implying that full field development and scale strategy do not need to consider barium-rich water.
Scale predictions were performed for various strategies; formation water production, seawater injection, produced water re-injection and low salinity/low sulphate water injection. Moderate strontium sulphate (SrSO4) and calcium carbonate (CaCO3) scaling are expected in the production wells. If third party barium-rich waters are tied-in, the topside barium sulphate (BaSO4) scaling risk increases.
This work has shown: Careful evaluation of formation water samples/analyses reduces uncertainties associated with water compositions and increases confidence in results and decisions. Underlying geology can influence formation water compositions. Good quality water sampling is important for later phase field development and scale management.
Careful evaluation of formation water samples/analyses reduces uncertainties associated with water compositions and increases confidence in results and decisions.
Underlying geology can influence formation water compositions.
Good quality water sampling is important for later phase field development and scale management.
The implications for field development are: Seawater will be injected into the reservoir for pressure support with no need for sulphate removal plant. Produced water re-injection will gradually replace seawater to minimize environmental impact. Downhole scale inhibitor injection has been recommended to protect the upper completion.
Seawater will be injected into the reservoir for pressure support with no need for sulphate removal plant.
Produced water re-injection will gradually replace seawater to minimize environmental impact.
Downhole scale inhibitor injection has been recommended to protect the upper completion.
The choice of an integrated process modeling approach is function of information availability, data uncertainty, and the cross-discipline integration demand. Based on these parameters, the modularity, the multidisciplinary knowledge request, and the decision between feedforward or feedback control is defined. First, this paper discusses drivers and enablers to implement field life cycle management. To this end, right decisions are necessary to ensure that integrated asset optimization reaches the global optimum instead of local ones. The second part of this paper presents a case study describing a compositional production stream modeling to perform multiple flash calculations from the initial reservoir to the stock-tank conditions. The integration objective is to deliver robust fluid characterization to model the multiphase flow expansion process through a surface choke valve at the wellhead.
The surface separation process was defined as two stages: a high pressure stage and the stock-tank. This process represents the well testing route scenario.
A multi-rate well test was performed in real field scale to provide input data for the investigation. The multi-rate well test consisted to execute a sequential step response disturbance. Each disturbance was followed by a transient and a steady state period "a priori" to a next step. Two types of well performance were analyzed: production with stream composition variation caused by near wellbore reservoir gas/water coning and production with constant stream composition. The simulation was implemented in the software Hysys from Aspentech to provide the fluid properties and the stream composition for modeling the multiphase flow expansion process through a choke valve in wellhead conditions.
The results demonstrated that multiphase flow expansion process through the valve is neither isenthalpic nor isentropic. For the outlet valve (downstream choke) temperature calculation, it was found an absolute relative error of 8% for the isenthalpic flash and 14% for the isentropic flash. These errors corresponded to the higher pressure drop across the valve. The agreement between calculated and measured valve outlet temperature was achieved when equilibrium calculation considered an adiabatic efficiency coefficient (
Enhanced oil recovery (EOR) is a general application used in mature oil fields to generate additional reserve growth. Several types of EOR applications are implemented in the oil industry. One such application is the injection of gas into a reservoir as a gas displacement recovery (GDR) mechanism to induce additional reserve growth. A specific type of GDR application is the immiscible water-alternating-gas (IWAG) displacement process. In this application a slug of water is put into an injection well, followed by gas, which exists as a separate phase from the water and oil. Water and gas injection slugs are alternated until the designed amount of gas has been injected, or as field production dictates. Continuous water (case water) is typically injected after the IWAG process.
Herein, the state-of-art of IWAG EOR is described from an extensive literature review. First, the theories of the recovery mechanisms that cause IWAG to produce incremental oil are described. These mechanisms include viscosity reduction, 3-phase relative permeability, oil swelling, and oil film flow, all of which are a function of fluid and rock-fluid interactions. Next, salient laboratory studies are summarized, including micromodel and core floods. These studies test pore-level characteristics, displaying ranges of residual non-wetting phase saturations (hydrocarbons) down to 0.13 to 0.25 and incremental oil recovery ranging from 14% to 20% of OOIP. Some experiments isolate a specific recovery mechanism in order to determine its validity and contribution to recovery. Studies generally point to the conclusion that the gas type shows no discernable difference in recovery character.
The paper concludes with a synopsis of results from small-scale field trials and field-scale projects in both heavy and light oil. Both simulation modeling and field trials are summarized. Projects have been implemented with varying types of gases, WAG ratios, and gas slug sizes, resulting in incremental reserve growth being reported in the range of 2 to 9%. The fundamental immiscible recovery mechanisms in IWAG can produce lower cost and faster response EOR projects, with moderate recovery efficiency gains.