Remya Ravindran Nair, Evgenia Protasova, Torleiv Bilstad, and Skule Strand, University of Stavanger Summary This research focuses on membrane-separation efficiencies by adjusting the ionic composition of deoiled produced water (PW) and evaluates the possibility for smartwater production from PW for enhanced oil recovery (EOR) in carbonate reservoirs. Key characteristics of smartwater for carbonate reservoirs are increased concentrations of divalent ions and low concentrations of monovalent ions compared with seawater. In this research, PW was pretreated with media filters, which resulted in 96 to 98% oil removal. This deoiled PW was used as feed for nanofiltration (NF) membranes. NF-membrane performance was evaluated in terms of flux and the separation efficiencies of the key scaling ions calcium (Ca) and barium (Ba). No membrane fouling was observed during the experiments. The results showed no Ca dissolution, which could affect chalk-reservoir compaction. A process scheme is proposed for smartwater production by ionic selection from seawater and PW at an operating pressure of 18 bar. Energy-consumption analysis for smartwater production before membrane treatment concluded NF to be economic over other desalination technologies. The power consumed by NF membranes for smartwater production at 18 bar is calculated at 0.88 kWh/m Introduction PW is one of the major waste streams from the oil and gas industry and should be managed in an environmentally sustainable manner. PW treatment is concerned with contaminants such as solids and residual oil, together with production chemicals (Fink 2012). The current water/oil ratio (WOR) in oil production is 2:1 to 3:1 worldwide. Onshore-treatment costs of PW from the North Sea differ from 0.19 to 3.40 USD/bbl of PW (Duhon 2012).
Imaging the geology subsalt and at the transition between extra-salt and subsalt has been a challenge at Mad Dog even with extensive seismic data coverage, including two WATS surveys and multiple NATS surveys. WATS acquisition and TTI velocity model processing generated major improvements in the image at Mad Dog. One of the observations of a previous TTI project is the presence of a strong orthorhombic anisotropic effect in a salt mini basin above the field. This finding led to the decision to reprocess the Mad Dog data with a tilted orthorhombic (TOR) velocity model. The main objective of this project is to build an orthorhombic velocity model with nine parameters compared to five with the TTI processing. The TOR anisotropic parameters are generated with the latest FWI and tomography techniques and take guidance from the stress field from a geomechanical model. The outcome of the project is very encouraging with results including better constructive imaging in crucial areas of the field, an incremental increase in signal-to-ratio everywhere and increased fault resolution. The TOR velocity model will be used to migrate a future ocean bottom nodes survey to address some of the remaining imaging challenges.
Presentation Date: Wednesday, October 17, 2018
Start Time: 8:30:00 AM
Location: 208A (Anaheim Convention Center)
Presentation Type: Oral
Nair, Remya Ravindran (Department of Mathematics and Natural Science) | Protasova, Evgenia (Department of Mathematics and Natural Science) | Bilstad, Torleiv (Department of Mathematics and Natural Science) | Strand, Skule (Department of Petroleum Engineering, University of Stavanger)
Produced water (PW) management and reuse of PW has economic and environmental benefits compared to PW discharge. This research focuses on membrane separation efficiencies in adjusting the ionic composition of de-oiled PW and evaluating the possibility for smart water production from PW for enhanced oil recovery. Key characteristics of smart water for carbonate reservoir is increased concentration of divalent ions and depletion of monovalent ions.
Dual media is used for oil removal from PW. De-oiled PW is feed for Nanofiltration (NF) membranes for separation of barium and calcium ions. Combination of NF retentate with seawater (SW) as feed and NF permeate from PW is also considered. PW permeate is mixed with SW spiked with determining multivalent ions, sulfate or phosphate, which alter wettability of oil reservoirs.
Currently, smart water is produced by adding chemicals to fresh water or low total dissolved solids (TDS) water produced by reverse osmosis (RO) or flash distillation. Using de-oiled PW as feed to NF will reduce power consumption, footprint and chemicals. PW can be reinjected into reservoirs after removing scale-causing ions. By injecting low barium and calcium PW brines, the frequency of scale squeezes will decrease. Membrane performance is evaluated for flux and separation efficiencies of calcium and barium. Barium concentrations in synthetic PW is increased 20 times the original concentration in Tor Field in North Sea, for evaluating NF separation efficiency. Negligible amount of barium is present in NF permeate at pressures of 8-12 bars resulting in a permeate flow rate of 200 L/h for a membrane area of 2.6 m2.
Increased sulfate concentration in smart water enhances recovery by 40 % of original oil in place. However, BaSO4 scalingcan be initiated even with negligible barium concentration if high sulfate level is present in the injected brine. The novelty of this research resides in the use of non-precipitating phosphate replacing sulfate for smart water production, simultaneously decreasing barium concentration and scaling potential of PW. However, precipitation of calcium occurred in presence of high concentration of phosphate. Power consumed by NF membranes for smart water production is calculated at 0.37 kWh/m3.
Ronald, Andy (BP) | Han, Xiaogang (BP) | Webster, Mike (BP) | Zett, Adrian (BP) | Howard, Rodney (Halliburton) | Love, Alexandra (BP) | Lavery, David (Halliburton) | Guo, Weijun (Halliburton) | Quintero, Luis (Halliburton)
The Machar oil field is part of a collection of salt diapir structures in chalk formations in the UK Central North Sea. Water-flood production began in 1998 and historically Pulsed Neutron Logging (PNL) was used to track GOC's, WOC's and evaluate up-dip production targets prior to development. Now, towards the end of the decline stage, attention is focused on the timing of depressurisation, with PNL data used to calculate Sorw and Sorg for SCAL validation and full field modelling to maximize recoverable reserves. Different vintages of pulsed neutron data have been used in the workflow to guide the development of new acquisition and analysis techniques, which aim to minimize subsea rig time without compromising the value of information extracted from the data.
While Sigma is still a reliable nuclear attribute in determining saturation changes in areas imbibed with high formation water salinities, it has its limits in other parts of the field. This paper will present the use of “forensic” fluid identification information, water salinity in particular, to constrain the Sigma model and its use in quantitative evaluation. Other nuclear attributes are screened, characterized and described for further use in numerical evaluation.
To address the displacement complexity, in particular the variable salinity across the well's stratigraphy, other nuclear attributes were selected to reduce the uncertainty around residual oil to water (Sorw) calculations. While C/O logging does offer an independent salinity option, the method suffers from its slow logging speed requirement that is not practical during subsea well work operations. Instead of continuous and multiple C/O passes, a stationary methodology was developed to test the Sorw at suitable points. The methodology was validated against multiple passes over short intervals and in combination with other nuclear attributes integrated into an interpretation workflow. Further investigation of yard and field data of a number of nuclear attributes, indicates that combining stationary Inelastic with continuous Capture Yield data will reduce both the uncertainty around Sorw and the rig time. Of particular use is the Chlorine Yield that can be used quantitatively for such applications in chalk reservoirs.
This paper will describe the approach taken to drive new data acquisition to minimize the risk in subsea well work by reducing the logging time along with data integration into the reservoir model to improve depressurization timing and maximize field recovery.
Chatterjee, Amitabha (Schlumberger) | Datir, Harish (Schlumberger) | Baig, Mirza Hassan (Schlumberger) | Horkowitz, Jack (Schlumberger) | Grau, Jim (Schlumberger) | Goonting, Jeremy (ConocoPhillips) | Haneferd, Helen (ConocoPhillips) | Tompkins, Dianne (ConocoPhillips) | Wendt, Brett (ConocoPhillips)
Copyright 2015, held jointly by the Society of Petrophysicists and Well Log Analysts (SPWLA) and the submitting authors. This paper was prepared for presentation at the SPWLA 56th Annual Logging Symposium held in Long Beach, California, USA, July 18-22, 2015. ABSTRACT The Greater Ekofisk area produces from naturally fractured chalk reservoirs in the North Sea. While knowledge of the reservoir itself is essential, it is equally important to have a thorough characterization of the overburden that lies above. Continuous measurements with high vertical resolution are required to address numerous challenges for drilling, completions, sustainable production, and abandonment operationsnarrow drilling windows, wellbore stability, compaction, subsidence, fault reactivation, and fluid containment-that increase costs and reduce well life. Previously integrated core studies, acoustic measurements, seismic surveys, and well logs document complex mineralogy: mixed clays, quartz, feldspars, carbonates, and iron-rich heavy minerals. In addition, these highly porous overburden shales contain a variable amount of organic matter and naturally occurring free-gas volumes. Pressure seals, swelling clays, fracture potential and orientation, and rock strength have mineralogical sensitivity below seismic resolution. In prior work in the field, building a proper geologic and geomechanical model at the appropriate scale was attempted with well logs, but the available capture-only spectroscopy data could not provide the richness required for solving the high number of unknowns present in the nonreservoir overburden rocks. The lack of estimated organic matter volumes combined with the uncertainty in clay types and volumes in an iron-rich environment in the presence of free gas challenged the petrophysical models. Recently, a reevaluation was attempted using a new high-definition spectroscopy tool, guided by the prior knowledge of the overburden rocks. Measurement of both capture and inelastic spectra provided greater confidence in the clay analysis from direct aluminum measurements. Also solved were the previously unresolved organic matter through carbon measurement, dolomite through magnesium measurement, and rhodochrosite through manganese measurement. These new measurements have led to a significantly increased confidence in the petrophysical model, allowing it to evolve further.
The South Arne Field, located in the Danish sector of the North Sea, has been producing oil and gas since 1999 with an active waterflood since 2000. Producers and injectors are primarily horizontal with sliding sleeve completions targeting both the Ekofisk and Tor chalk formations. South Arne is currently in exploitation modewith a new (Phase III) development program. Phase III includes two new platform installations, a two-kilometer umbilical bundle and an eleven-well drilling program targeting the northern extension of the field. This paper discusses the first five Phase III wells, focusing on stimulation design, lessons learned from the fluid testing, experiences, and the continuous improvement of the operational execution process.
New producer and injector stimulation designs are generally based on a pad-acid procedure in which a cross-linked gel pad is followed by an in-situ cross-linked hydrochloric (HCl) acid treatment, to create viscosity contrast for diversion and differential acid fracture etching for sustained conductivity. The acid fracture treatment is then followed by a closed fracture acidizing (CFA) step to enhance near-wellbore fracture conductivity. For wells completed in zones that have the potential of short-circuiting to neighboring wells, lower rate and smaller volume HCl matrix treatments are pumped. The Phase III stimulations to date have been conducted through ball drop sliding sleeves, with the number of zones ranging from 10 to 14.
Establishing Phase III success has required extensive QA/QC testing to optimize the stimulation fluid systems and, in particular, the acid corrosion inhibition program. Use of real-time bottom-hole temperature measurements during stimulation treatments has enabled optimization of corrosion inhibitor loadings, resulting in both an environmental benefit and financial savings. The stimulation treatments are performed simultaneously with drilling operations, therefore extensive work was required to ensure that stimulation and drilling activities are safely executed without interference. Both platforms were initially designed to optimize productive time during stimulation operations, however as the project evolved, thorough risk evaluations pointed to the need to modify operating plans. Rigorous marine and vessel audits were performed to ensure that stimulation vessels could operate safely and effectively from both a marine and stimulation job execution standpoint. The design, testing and advance preparation for the South Arne Phase III program has resulted in safe and effective treatment execution.
Vejbaek, Ole Valdemar (Hess Denmark) | Bech, Niels (Geological Survey of Denmark and Greenland) | Christensen, Søren Amdi (Hess Denmark) | Høie, Andreas (Hess Denmark) | If, Flemming (Hess Denmark) | Kosco, Ken (Hess Denmark) | Schiøtt, Christian Rau (Hess Denmark) | White, Gillian Nicola (Hess Denmark)
The South Arne field presents an example of a North Sea chalk field with an oil distribution strongly affected by fluid dynamics, even at initial conditions. The oil-saturation variation in the South Arne field is effectively modeled with free-water-level (FWL) surfaces, the height above which defines the capillary pressure of oil vs. water. This FWL is in the shape of an elongated dome with a relief on the order of 200 m, corresponding to a smooth, lower amplitude version of the field structure itself. Dip of the FWL exceeds 100 m/km locally. 2D geological time-scale reservoir simulation is successfully deployed to replicate observed oil-saturation distribution and geometry of the FWL surface. This modeling greatly improves the understanding of and ability to predict the saturation distribution. The anomalous doming of the FWL is thus shown to be because of anomalous lateral-pressure gradients mainly in the water phase, whereas pressure measurements show the oil phase to be without lateral-pressure gradients. The main doming occurs where the oil extends vertically down to a seal at the base of the reservoir. The strong FWL dip is thus maintained on geological time scales (but less than 5 million years) because of low relative permeability to water, whereas oil flows just as readily as in other chalk fields. Because the dip is controlled mainly by low relative mobility of the water, the dip tends to vanish in parts of the field where a water leg is present in permeable rock beneath the oil to allow dissipation of anomalous water pressures.Partial- to full-preproduction imbibition has been identified and modeled in some flank areas. This explains why these parts produce water while other areas at similar saturation and porosity levels flow oil owing to drainage conditions. Identification of degree of imbibition is thus of paramount importance for optimal well placement and prediction of performance. An additional anomaly is found on the northeast flank of the field, where oil in drainage conditions is found deeper than anywhere else in the field. This deep occurrence of oil owes its presence to an anomalously permeable sandy layer close to the northeast flank, stratigraphically above the reservoir. This layer partially drains overpressure, thereby allowing oil to move down the flank from the main field, again because of water-phase-pressure variation, possibly allowing oil to spill into the sandy layer.
Mærsk Olie og Gas AS as operator for the Danish Underground Consortium (DUC) has successfully planned and delivered an Observation and Monitoring well in the Halfdan field located in the southern part of the Danish North. Although not entirely unique to the industry (for further examples see Richardson, 19771; Widmyer, 19872; Wannell & Ezekwe, 19923) this will be the first well of its kind for Mærsk Oil and the DUC placed in a chalk reservoir.
This paper describes the planning and execution phases of the monitoring and observation well legs, summarizing the formation evaluation results primarily related to remaining oil saturations. The data derived from the evaluation program enables an evaluation of the success of the novel wells pattern design in the Halfdan field, enabling optimization of the reservoir recovery, in addition to confirming the vertical extent of the hydrocarbon column.
As oil and gas fields mature, the monitoring of production-induced changes becomes crucial to sustain, optimize, and improve production levels. Enhanced recovery techniques are applied to extend the field life, as a result reservoir behavior, including vertical and lateral sweep, becomes more complex and challenging to model.
Water injection is a common practice used to maintain the reservoir pressure and enhance oil sweep; yet sweep efficiency is not always equal, with water tending to move heterogeneously through the reservoir seeking higher permeability pathways and leaving trapped/un-swept oil behind. The fluid movement and distribution within the reservoir characterises the efficiency of the production system. Such inherently complex and capital intensive nature of understanding and optimising the recovery mechanism behoves the developer to acquire information to evaluate and enhance the recovery mechanism targeting maximising returns.
Monitoring and Observation wells allow the detection of in-situ fluids, enabling modification and enhancement of the dynamic modelling, assist with evaluation of the applied IOR technique, and lay the foundation for potential future EOR opportunities. The two-pronged well provides an early indication of the recovery mechanism success in terms of sweep efficiency, and is a guide to further performance optimisation; additionally it is an opportunity to identify and develop any un-swept volume.
The Halfdan field is situated in the Danish North Sea Central Graben approximately 250 kilometers off the West coast of Denmark, and is located between the Dan and Skjold fields. The Halfdan reservoir is Maastrichtian and Danian aged chalk characterised with relatively high porosity (25-35%) and low permeability (0.5-2 mD). Halfdan was discovered in 1998 with a 30,000 ft long horizontal well drilled from the Dan field. The first vertical well was completed in 1999. First production from Halfdan was obtained in late 1999.
Yu, Huijuan (ConocoPhillips) | Sorensen, Sindre (ConocoPhillips) | Sudan, Hari Hara (ConocoPhillips) | Ludolph, Brian (ConocoPhillips) | Burgess, Aaron Glen (ConocoPhillips) | Dahl, Ellen Bie (ConocoPhillips) | Hagen, Nina Elisabeth BjÃ¸rnevoll (ConocoPhillips) | Kuhlmann, Sonja (ConocoPhillips) | Pacheco, Carlos (ConocoPhillips) | Wendt, Brett Lee (ConocoPhillips) | Coral, Mario G (ConocoPhillips)
The concept of uncertainty, risk, and probabilistic assessment is increasingly employed as a standard in the E&P industry to assist in development and investment decisions. The Tor field in the Greater Ekofisk Area of the North Sea is a producing chalk field, which has a 35-year production history and aging facilities. This naturally fractured chalk reservoir has had limited water injection and experienced rapid decline. An integrated subsurface uncertainty study has been performed to support a potential redevelopment of the Tor field. This paper will demonstrate the integrated workflow for the uncertainty study and the methodologies used to overcome challenges in reservoir modeling and forecasting. The results of the sensitivity analysis and assisted history matching (AHM) process will be illustrated as well as how the results were applied in the evaluation of redevelopment options and in preparing future reservoir management plan.
The main challenges in reservoir modeling, forecasting and overall evaluation of the Tor field are: 1) Uncertainties outside the well control area. This results in a significant structure uncertainty, hence an even more increased uncertainty in structural dependent properties. 2) Uncertainty and implementation of inter-dependent static properties and their spatial distribution. The deterministic base case model is only one of thousands of property realizations from the geostatistical modeling process. 3) Uncertainty and systematic implementation of effective permeability. Effective permeability in the chalk reservoir is a combination of enhanced matrix permeability and “highways”. Predictability of potential “highways” not identified by existing wells is especially challenging. 4) Simulation time. These uncertainties will directly influence the determination of hydrocarbon in place, well placement, and waterflooding efficiency and add risk to the production forecast used to justify field redevelopment.
The workflow was: 1) Identification and framing of uncertainty parameters. 2) Complete static and dynamic parameters analysis and integration. 3) Comprehensive sensitivity analysis and AHM. 4) Forecasting based on multiple calibrated models to reach the rigorous probabilistic production profiles. The approach used include: 1) Realization of structure uncertainty and associated properties by a robust approach, which is advantageous for the AHM process. 2) Employment of multiple property realizations. 3) Use of a 3D seismic attribute for capturing potential highways uncertainty and for systematic effective permeability implementation. 4) Addressing uncertainty in water flood sweep efficiency.
From the integrated workflow and robust methodology, a suite of “good quality” AHM models with equal probability are obtained. AHM has narrowed down the uncertainty range and from post-AHM analysis the initial resource range and main influential parameters on development are determined. As one of the best practices, we recommend using across sampled representative models with well & operation uncertainties rather than a specific P10, P50 or P90 model to make final probabilistic forecasts.
Kent, Anthony W. (ConocoPhillips) | Burkhead, David W. (ConocoPhillips) | Burton, Robert C. (ConocoPhillips) | Furui, Kenji (ConocoPhillips) | Actis, Stephen C. (ConocoPhillips) | Bjornen, Kevin (ConocoPhillips) | Constantine, Jesse J. (ConocoPhillips) | Gilbert, W. W. (Trey) (ConocoPhillips) | Hodge, Richard M. (ConocoPhillips) | Ledlow, Lewis B. (ConocoPhillips) | Nozaki, Manabu (ConocoPhillips) | Vasshus, Arne (ConocoPhillips) | Zhang, Tao (ConocoPhillips)
This paper describes the design, testing, installation, and performance of the first fully completed well by use of an intelligent inner completion inside an uncemented liner with openhole packers for zonal isolation. The well-design concept evolved from technical challenges associated with completing long cased-and-cemented laterals in the mature Ekofisk waterflood. The term fully completed implies full reservoir access along the pay length for production and high-rate matrix acid stimulation by use of limited entry for fluid diversion within well segments. The paper covers the development and qualification of customopenhole 7 5/8-in.-liner components that can handle high differential pressures and severe temperature fluctuations of 200°F; the marriage of this complex liner with a five-zone intelligent-completion system; and results from 1 year of system-integration testing. The paper also discusses the strategic placement of both mechanical openhole and inner-string packers based on caliper and drilling logs; challenges met and overcome during installation; and comprehensive downhole-gauge data that confirms the performance of each component before, during, and after the stimulation. The Ekofisk field waterflood began in 1987 and continues to date, exceeding expectations for improved oil recovery while mitigating reservoir compaction. As the waterflood matures, new wells are more often found partially water-swept. Limited infrastructure for lifting and handling the high water production has led to increased emphasis on isolating these water-swept intervals. Cased, cemented, and perforated completions have traditionally been used for this service. Effective placement of cement is challenging in horizontals 4,000–8,000 ft in length, where rotation of the liner is not possible and high effective-circulating densities limit rates during cementing. Wide variations in reservoir pore pressures, often in excess of 2,000-psi difference along the lateral, are typical of the Ekofisk chalk and compound the difficulties of cementing. As a result, a new method for zonal isolation has been developed to ensure the success of future infill-drilling campaigns. The design and careful planning that went into the fully completed openhole uncemented-liner strategy resulted in a successful field trial and has proved this solution to be an effective alternative to cemented reservoir liners in long horizontals where zonal isolation is critical. Use of the intelligent-well system (IWS) allowed offline acid stimulation without rig, coiled-tubing, or wireline intervention. What would have traditionally been a significant water producer, with three water-swept zones totaling nearly 2,000 ft across a 4,000-ft reservoir section, has turned out to beone of the best oil producers in the field, with nearly zero watercut. Production results show high productivity with highly negative acidized-completion skins.With large investments in intelligent completions to provide zone-specific inflow control and water shutoff, isolation outside the liner becomes much more important. Over recent years, the Ekofisk wells have illustrated the difficulty of achieving effective cement along lengthy reservoir targets. The openhole fully completed solution combining an accessorized uncemented liner with an inner intelligent-completion string will allow operators to push the limits in terms of lateral length while maintaining full control over producing and nonproducing zones.