Sand production is very common in the gas wells of the Adriatic Sea. Accurate field surveys have been conducted before and after sand production has occurred in wells where no sand control methods had been initially introduced. Unlike the numerous other papers dealing with sand production, this one describes the sand production observed in low permeability gas-bearing formations which include a significant amount of clays. The main parameters inducing sand production are identified and an empirical correlation is established which enables its prediction. Moreover, the influence of parameters such as depth, drawdown, depletion, gas rate, water gas ratio etc. on the occurrence of sand production is determined. The paper also reports the results of a sand flow test performed in a gas field situated in the surveyed area. Finally, these results are discussed in terms of geological history of the Northern Adriatic Basin.
From a scientific point of view, sand production prediction is one of the most complex problems that has been addressed by the oil industry over recent years. Yet, the economical importance of a sound prediction methodology leading to an optimized completion strategy is such that many corporations have dedicated vast resources towards the solution of this problem. De facto surveying the literature reveals that a large number of models have been proposed to predict sand production. Unfortunately none of them has been validated to such an extent that it can be considered as a standard by the industry. As a consequence a large gathering of sand production data was undertaken. After proper data analysis it is possible to demonstrate that, from the engineering point of view, sand production is a relatively simple phenomenon governed by a few key parameters. Available models are prescreened for their capacities to account for these parameters. The selected models are then calibrated and validated against sand production field data with a sufficient degree of accuracy for operative purposes. Introduction From an industrial point of view, sand production prediction is essentially an economical problem. When the sand production risk is under-evaluated, the problems which have to be confronted are numerous: safety, downhole and surface installation erosion, well cleaning which may require major work overs and impose production delays, etc. On the other hand, when the sand production risk is over-evaluated, the problem often becomes the unnecessary reduction of the productivity of the wells which may require the drilling of further wells to achieve the targeted production for a given reservoir (an average productivity index reduction of 30 % for internal gravel packed wells is a fair figure derived from Agip's experience). Consequently, the ideal strategy for an oil company would be to know right from the beginning of the production of a well for how long it can be produced without sand control and then to decide when to do a remedial work-over and if such a work-over is economical when compared to the immediate placement of a sand control completion. Finally, as the critical conditions of sand production may vary greatly for different wells from a given reservoir, such an analysis ought to be made on a well to well basis. These technico-economical objectives being set, one can then start to establish the elements of an efficient methodology of sand production management:–a sand production prediction model which is simple and versatile enough to be run on a well to well basis and which can be integrated into 3D reservoir simulations to allow the economical assessment of different completion choices;–a sand production prediction model which is reliable enough to avoid major errors;–modelling the Earth being a very delicate science, a site specific calibration technique for the model should also be available;–finally, even when calibration has been made, a sand monitoring system should also be available to detect the precursory signs of sand production and avoid major accidents. Knowing that many scientific studies had been performed over the years about sand production prediction. it was decided to avoid the duplication of efforts and to start from a completely different perspective. Keeping in mind the industrial objectives and prerequisites set above, the study therefore followed the five steps listed below:gather an important amount of sand production data from the field;analyse these data along with laboratory measurements to try to understand the physics of sand production as revealed by the field evidence;identify the key parameters governing this physics;calibrate available models on such data and evaluate which ones were the most reliable and the simplest; P. 227
Many gas reservoirs in the Adriatic Sea, offshore Italy, are formed of laminated, low permeability dirty sandstones, requiring gravel packing for sand control. Numerous gravel-packed wells are either sanded up and shut in, or are underperforming due to fines plugged gravel-pack screens, which cannot currently justify the expense of an immediate and cost-prohibitive full rig workover. Frac and packs are performed to increase productivity bypassing near wellbore damage, interconnecting multiple sandstone layers and decreasing fluid velocities in the formation, thus reducing fines production. Significant interest exists to enhance fracture performance, deferring and reducing re-completion costs. This paper discusses various rigless performed rehabilitations of failed sand control completions, highlighting the evolution of fracture fluid selection, optimization of the fracture placement and achieved geometries with seawater-based visco-elastic surfactant fluids and the use of speciality glass fibers for fracture pack stabilization and enhanced proppant transport. This combined rehabilitation technique enabled screenless sand control completion and is allowing low cost rehabilitation of plugged or failed sand screens and the development of any numbers of gas layers which otherwise could not be drained using conventional sand control technologies. This completion technology potentially allows to significantly adding gas or oil reserves, the development of the normally by-passed upper gas layers, which would require costly workover re-completion using conventional technologies. Procedures, experiences and results are presented, validating the -enhanced visco-elastic surfactant fracturing concept enabling screenless sandface completion for controlling sand production. Rigless rehabilitation has confirmed being an efficient solution and allows cost-effective production increase. Background Evaluation of numerous fracturing treatments performed in the Adriatic Sea, confirmed the selected fracturing methods and fluids used were not optimizing gas production. In-depth analysis of past fracture performances showed that the conventional frac fluids in use cannot create the fracture geometries needed - wide and short - to produce the Adriatic Sea reservoirs effectively. Required mature tip-screen-out fractures are not obtainable with brine and polymer-based fluids; and fracture geometries are unfavorable in respect to fracture length and width - brine created fractures were not sufficient, HEC fluids generated fractures were too long and too narrow, for effective gas production. Table 1 summarizes the results of the analysis using brine, HEC and the industry's first visco-elastic (VES) fracturing fluid (ClearFRAC) during fracturing lithologically similar nearby Emma gas field and the application of the visco-elastic fracturing fluid - also called VES - results accomplished on Giovanna gas field.
Summary This paper discusses the design and execution of dual-zone gravel packs in very shaly and silty formations of median sand grain size less than 30 um. An oversized gravel was selected for sand control and, as consequence, the openhole gravel-pack technique was adopted to reduce the effect of intermixing between formation and gravel-pack sand. During the completions in the first five wells, we encountered and solved several operational problems, including those involving (1) borehole stability, (2) setting of inflatable packer for zone isolation, (3) hole preparation, and (4) gravel placement. From the lessons we learned, another 11 wells were completed with dual openhole gravelpacks without significant problems. After 1 year of production, the flow performance from the wells met or exceeded the initial objectives. Introduction The Giovanna field is a gas-bearing reservoir situated in the offshore Adriatic area (Fig. 1). It is a multiplayer reservoir comprising 30producing intervals that consist of thin interbedded layers of partially unconsolidated sand and shale. The total pay zone has a thickness of more than700 m and is located at depths between 1200 and 2000 m. As a result of the small grain size of the sand and the high clay content, the reservoir rock has a very low effective gas permeability (10 to 30 md). To develop this reservoir, it was necessary to make provisions for a completion that would prevent the movement of the incompetent sands. Because of the low formation permeability, sand consolidation was immediately rejected as a suitable technique for providing sand control and consideration was given to mechanical methods (gravel packing). In many cases, the inside-casing gravel pack (ICGP) introduces a large pressure drop across the completion,1 with a consequent reduction in the production capacity and performance of the well. This result is especially true when, as in this case, a very small size of gravel (100 to 120 U.S. mesh)is required. On the other hand, the openhole gravel pack (OHGP) generally is not recommended in the presence of clays because there is a high probability of intermixing with gravel. After careful analysis of the advantages and disadvantages of each of these techniques, we decided provisionally to complete all 16 wells with OHGP's in dual parallel completion. With only 16 wells available to develop the reservoir, it was necessary to combine the 30 producing intervals into 11 producing pools. This decision was based on homogeneous pore pressure and depletion of the commingled producing intervals. As a result, it was necessary to complete long intervals (40 to 60m) for the exploitation of the gas resources. Because no previous experience has been gained with gravel-pack completions in very fine and silty sand, we decided to proceed with the following course of action.Perform a sand-flow test (SFT) to verify that sand production would occur.Execute a dual OHGP in the first well to ascertain the feasibility and efficiency of this type of completion. Furthermore, a single ICGP was executed at a later stage and confirmed that the OHGP was the most appropriate completion for the Giovanna field. This paper will illustrate the problems encountered, the remedies introduced, and the results obtained from these completions, with particular reference to (1) evaluation of the risk of sand production, (2) gravel-size selection, (3) borehole stability, (4) zone isolation, (5) hole preparation,(6) gravel placement, and (7) flow efficiency.
Summary In the Adriatic offshore area, conventional cased-hole gravel-pack completions have generally produced low flow efficiencies (10 to 50%) from the multilayered reservoirs of low-to-medium gas permeability (1 to 50 md). This has been attributed to the poor communication between the wellbore and the producing layers, caused by limited exposure of the interval and poor filling of the perforation tunnels with gravel. This is confirmed by openhole gravel-pack (OHGP) completions where much higher flow efficiencies are observed. The frac-pack technique, which combines gravel-pack and fracturing technologies, can improve communication between the layers in perforated completions by creating a vertical fracture with high conductivity and the injectivity necessary to fill the perforation tunnels. In addition, any existing near wellbore damage will be bypassed. This paper reviews the field experience gained from over 80 fracpack operations that have been performed during the last 2 years in the thin, interbedded layers of poorly consolidated sand and shale commonly found in the Adriatic area. Owing to their relatively low permeability, these formations can be fractured with nonviscosified fluids at pump rates less than 1 bbl/min. Consequently, completion brine was selected as the treating fluid. To reduce operational time and costs, the frac-pack treatments were carried out with the gravel-pack assembly in place and injection rates of up to 7 bbl/min were used with gravel concentrations staged from 1 to 4 lbm/gal. Fluid losses were encountered after the frac-pack treatments and were controlled by spotting a small pill of drill-in fluid (containing calcium carbonate) that was sized to bridge inside the screens. This paper presents the production performance of the frac-pack completions and establishes guidelines for future applications of frac-pack operations in similar reservoirs. Introduction The gas reservoirs in the Adriatic are frequently made up of interbedded layers of poorly consolidated sand and shale. Large amounts of silt and carbonates are present, and permeabilities range from 1 to 50 md. Multizone completions (Fig. 1) are necessary for efficient reservoir management because of the presence of numerous producing zones with varying permeabilities and pore pressures. Gravel packing has been used extensively to control sand production in new wells and during workover operations; OHGP completions have yielded extremely good results with an average flow efficiency (FE) of around 90%. Dual-zone OHGP completions have been realized, but they are generally considered impractical because of wellbore deviation, close proximity of adjacent water-bearing layers, and the operational risks and costs where milling of casing is required.
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