Fuxa, Jason (Baker Hughes) | Di Giampaolo, Paolo (Baker Hughes) | Ferrara, Giovanni (ENI) | Di Pietro, Mario (Baker Hughes) | Sportelli, Marco (ENI) | Ripa, Giuseppe (ENI) | Di Campli, Antonio (Baker Hughes)
This paper details a field application of Shaped Memory Polymer (SMP) material for sand management delivering an innovative approach for sand control completions. The use of the technology has enabled profitable exploitation of residual reserves in a mature gas field offshore Adriatic Sea. The paper reviews details of the field deployment, with both economic and well performance results described.
The Barbara Field was discovered in 1971 and 102 wells have been drilled to date. The trap is a very gentle, slightly asymmetrical anticline made by Pleistocene sandy turbidites,sedimented on the underlying carbonate substrate. Methane gas bearing layers have been sealed by several argillaceous intercalations that worked also as the source rocks of this multilayer reservoir. The sandy layers in this Pleistocene sequence, Carola Formation, have thickness ranging from few centimeters up to some meters, and porosity from 22 up to 33%. Isolation of multiple gas-water contacts and fines production have been two crucial issues while producing the field.
Since 2000, all seven Barbara platforms have required workovers by means of performing sidetracks. Due to the reservoir characteristics, the well interventions have been completed with multi-layer, stacked cased-hole sand control completions. Despite a continuous improvement of procedures and technique, the traditional sand control methods have been efficient but were no longer profitable, due to challenging market conditions.
An open-hole completion using SMP combined with zonal isolation and selective production has proved to be an effective alternative to cased-hole sand control. This novel completion approach resulted in a significant reduction in both cost and rig time. It is estimated that nearly two weeks of rig time was saved and an overall workover cost reduction of approximately 35%, with further efficiencies to be realized on upcoming deployments. To date, the completion has proved to be an effective sand control method, with no produced solids, no plugging effect, and gas production that has met expectations.
Lawal, Kazeem A. (First Exploration & Petroleum Development Company) | Ukaonu, Cyril E. (First Exploration & Petroleum Development Company) | Ovuru, Mathilda I. (First Exploration & Petroleum Development Company) | Eyitayo, Stella I. (First Exploration & Petroleum Development Company) | Matemilola, Saka (First Exploration & Petroleum Development Company)
Electrofacies modelling, which includes identification and grouping, is a critical part of reservoir characterisation. Because it governs the estimation and distribution of key rock and rock-fluid properties, the electrofacies model, to a large extent ((if augmented with core-derived information), determines the quality of static and dynamic reservoir models. Unfortunately, owing to the lack of a universally acceptable method, the outcome of electrofacies modelling is not always unique. This explains the usual difficulty in achieving a meaningful comparison of different reservoirs or correlating different packages, even with the same set of well logs.
To address the problem, this paper presents a set of mathematical models and simple workflows for quantitative characterisation and grouping of electrofacies in shaly sandstone formations. The gamma ray, density, and neutron, which are commonly available lithology-indicating and absolute-value reading logs, are integrated to define a quantity called composite shaliness parameter. The use of a simple scaling rule ensures that the values of the shaliness parameter are limited to the 0 - 100% range. To make the model universally applicable, the scaling of the shaliness parameter covers the ranges of values of the indicated logs in most shaly sandstone formations.
Although the models and workflow are intended to be universally applicable to all shaly sands to enable global benchmarking of formations as may be necessary, provision is made for local applications. In the latter cases, a simple procedure for adapting the scaling rule to specific local problems is presented.
Using field examples from the Niger Delta, the validity of the proposed method is examined. It is evaluated against mobility tests, core analysis and spectral gamma-ray log, which are techniques known for better reservoir characterisation at different scales. It is found that the results of the proposed method are in satisfactory agreement with findings from these reference characterisation techniques.
Ferrofluids are Fe3O4 based Magnetic Nano Particles (MNPs) and can be coated with a layer to form a super-hydrophobic material which selectively adsorbs oil. These colloidal ferromagnetic nano-particles show remarkable magnetic susceptibility. The ability of ferrorfluids was at display in the Gulf of Mexico and other oil spill clean-up. Excellent on-surface results suggest us to exploit its potential under sub-surface conditions too. The paper puts forward the potential on MNPs in EOR/IOR, proper production scenarios and techniques to inject this magnetically-controlled oil-adsorbing fluid through pad during hydraulic-fracturing operations.
Sodium oleate coated magnetite (Fe3O4) is found to be the best suited MNP constituent for pad fluid. Fe3O4 particles modified with sodium oleate have successfully been able to generate super-hydrophobic surfaces. Their average size ranges from ~5nm to 10nm, thus are capable of getting suspended in pad fluid during injection and passing through the oil bearing zone without plugging the pores during fracturing operation. MNP's motion can be forced and controlled by applying magnetic field which makes MNPs a great asset for improvisation of fracturing techniquesn (Experimentally tested over 100 different oil and heavy crude oil at FERMILAB, Batavia Illinois).
Injecting highly viscous Frackfluid ‘pad’ is amongst the primary part of fracturing job as it is used to initiate/propagate the fracture. Continuous loss of pad to formation will cause fracture propagation and at the final stage pad will be completely lost to the formation. Oleate coated MNP injected along with pad will selectively adsorb oil in the region where pad interacts with oil in formation. Initially applying outward magnetic field will cause solid MNPs to reach farther in formations, leaving behind the injected fluid in nearby formation, to sweep maximum reservoir volume. Second step is to apply an inward field towards the bore hole, which will force the MNPs to trace back into the wellbore along with adsorbed hydrocarbon on their surface. Magnetic field can easily drive these nanoparticles through tight/low permeable reserves and during heavy crude recovery. Their selective adsorption and hydrophobic nature can be of great significance in production through water bearing zones. Prepared MNP is both hydrophobic and lipophilic. Therefore Fe3O4 with sodium oleate could be soundly dispersed in the oil medium present in formations and recovered by applying magnetic field directed toward producing well.
This technique shows a new path for the industry in advanced fracturing operations involving fracturing through deep, heavy oil reserves, HPHT and highly water saturated reserves. Validity of the proposed process has been elucidated in the paper considering various technical and operational variables.
Loi, D. (ENI E & P.) | Mazzoni, S. (ENI E & P.) | Venturini, S. (ENI E & P.) | Baio, C. (ENI E & P.) | Borghi, M. (ENI E & P.) | Baldini, D. (ENI E & P.) | Italiano, F. (ENI E & P.) | Cantini, S. (Schlumberger)
Loi, D. (eni E & P) | Baldini, D. (eni E & P) | Venturini, S. (eni E & P) | Concas, A. (eni E & P) | Sportelli, M. (eni E & P) | Tassinario, V. (eni E & P) | Simeone, D. (eni E & P) | Buscherini, M. (eni E & P) | Rimoldi, A. (eni E & P) | Aurilia, B. (Baker Hughes) | Scandura, A. (Baker Hughes) | Ioannone, M. (Baker Hughes)
The declining production in many mature Adriatic fields is normally offset by drilling new deviated wells. Recent technology has shifted the focus from metric reservoirs to thinly laminated intervals (thin beds), which were, until now, not produced because of the difficulties in defining gas-bearing zones. The thin beds are challenging because the laminate is half an inch or less thick, far below the resolution capabilities of standard logging tools. Therefore, it is crucial that bottom hole cores are cut to assess the petrophysical and geomechanical rock characteristics. The small diameter of the boreholes and the unconsolidated nature of those reservoirs make coring operations very challenging; recent attempts have met with very poor results and negligible recoveries. A case history of an Adriatic well is presented in this paper, where nine meters of core were cut and successfully recovered (100%) from a 6-in.
Loi, Daniele (Eni E&P) | Mazzoni, Stefano (Eni E&P) | venturini, sandro (Eni E&P) | Baio, Carmelo (Eni E&P) | Borghi, Massimiliano (Eni E&P) | Baldini, Davide (Eni E&P) | Italiano, Francesco (Eni E&P) | Cantini, Stefano (Schlumberger)
Several offshore gas fields are present in Adriatic Sea (Italy), producing since the 60s from multilayer metric sand reservoirs. The declining production in these mature fields is normally offset by drilling new deviated wells. Recent technology evolution shifted the focus from metric reservoirs to thinly laminated intervals (thin beds), until now not produced due to difficulties in identifying gas bearing zones.
While gas identification in metric reservoirs can be normally achieved with standard petrophysical measurements, thin beds are challenging since lamination thickness is half inch or less and even advanced petrophysical logs struggle in discriminating gas from water in this environment. Conventional pressure gradient approach also does not work, since thin beds are often overpressurized and pressures are supercharged due to low mobility.
A new wireline formation testing approach for thin beds to discriminate gas from water zones was introduced, using a dual packer string with downhole fluid analysis capabilities, including fluid density measurement. This provided the possibility of testing very low permeability zones with high uncertainties in saturations. Dual packer tests were also successfully carried out in the underlying shale formation never considered before a real reservoir, revealing potential for gas production. The possibility to verify gas presence in zones with high uncertainties saved the cost of multiple well tests, optimized the completion strategy of the different reservoirs and allowed to increase the field production and reserves, reducing at the same time uncertainties in reservoir model.
Four jobs with dual packer and downhole fluid analysis to test thin beds were performed so far in Barbara NW, Barbara and Clara Fields, resulting in added gas reserves estimated in 2 Billions Sm3 and gas production higher than the one at fields startup several years ago. This is a remarkable result for development wells in a mature environment (balanced exploration), maximizing asset value. Based on these results, several gas fields producing today from metric reservoirs will be revisited in the very near future in order to start production from thin beds, untouched until now, with the advanced wireline formation testing approach described in this paper playing a key role.
Geological Setting and Field Development Informations
This paper describes case histories from Barbara Field, one of the most important Italian gas fields, and from Barbara NW Field, a satellite culmination of this giant field. The fields are located in the northern offshore sector of the Adriatic Sea. The traps are constituted by a smoothed anticline structure, oriented NW-SE, draped over a broad uplift in the underlying Mesozoic carbonate foreland. Barbara and Barbara NW fields are separated by a local syncline.
Gas is produced from multilayer metric sand reservoirs of Pliocene and Pleistocene age belonging to PLQ and PLQ1 sequence (Carola formation till upper Porto Garibaldi formation) of turbiditic origin alternated to shales (Ori et Al, 1986, 1983), at an average depth of 1400 m. Alternance of reservoir and shaly layers, as described above, constitute a classic multilayer system in which every layer may have each own Gas-Water Contact (GWC). The shaly layers often act as permeability barriers for the sand reservoirs, and they can be also considered the source rocks of the gas, of biogenic origin. Gas bearing reservoirs have a thickness variable from metric to thin layers of few inches or less. Porosity of these layers is very variable from 25% to thin beds environment with very low porosities.
Barbara Field was discovered in 1971, while Barbara NW structure was delineated by three apparaisal wells later in the 90s, then the field development started in 1999 with four wells targeting the thick sand layers of PLQ sequence.
Loi, Daniele (ENI E&P) | Mazzoni, Stefano (ENI E&P) | Gigliotti, Maurizio (ENI E&P) | Baio, Carmelo (ENI E&P) | Borghi, Massimiliano (ENI E&P) | Baldini, Davide (ENI E&P) | Italiano, Francesco (ENI E&P) | Cantini, Stefano (Schlumberger)
Polymer-free viscoelastic surfactant-based (VES) fluid systems are used to minimize damage to the proppant pack and to efficiently transport proppants into fractures. Proper selection of proppants and fracturing fluids for maximum propped fracture length requires reliable data and correlations for the impact of fracture fluid viscoelasticity and the effect of fracture walls on proppant settling. Current models and correlations neglect the important influence of fluid elasticity on proppant transport. This paper presents an experimental study that investigates the impact of fluid elasticity and fracture width and presents a general correlation for proppant settling in VES fluids.
Proppant settling experiments are performed in shear thinning VES fluids. Experimental data is presented to show that fluid elasticity plays an important role in controlling the settling rate of proppants. Increasing fluid elasticity can either increase or decrease the settling velocity depending on the rheological properties of the fluid and the properties of the proppants. A new experimental correlation is presented to quantify the settling velocity of proppants in VES fluids as a function of the fluid rheology and proppant size. It is shown that the VES fluids should be designed such that the relaxation time is greater than the critical relaxation time (Tcrit).
The productivity of fractured wells depends strongly on proper placement of proppants in the fracture. Experimental data/correlations are presented for the first time to show that the settling velocity of proppants is significantly impacted by the fracture width and in VES fluids this dependence is different than for the non-elastic fluids. Data is presented to show that settling velocity is reduced as proppant size becomes comparable to the fracture width. Results show that elasticity reduces the retardation effect caused by fracture walls. An experimental correlation to quantify the retardation effect due to fracture walls is presented. Proposed correlations highlight the advantages and limitations of using VES fluids for efficient proppant transport. These correlations can be directly used in fracture simulators for proppant selection and for the design of fracturing fluids.