The radioactive marker technique (RMT) appears to be a promising tool to evaluate the in-situ uniaxial vertical compressibility cM of deep producing gas/oil reservoirs. However, when the field consists of multipay layers with the porous-medium heterogeneity scale smaller than the marker spacing (10.5 m), great care must be exercised in the interpretation of an RMT survey. If the monitored depth interval incorporates thin clayey layers or the measurement is made in an active pumping well, cM can be grossly underestimated. Moreover, rock may expand, with the expansion correctly recorded by RMT. In the present paper, a set of RMT measurements made by Eni-E&P over the past decade in three deep boreholes of the Northern Adriatic basin are simulated with the aid of a 3D poroelastic model solved by finite elements (FEs). Use is made of the much detailed lithostratigraphies of the test holes and the cM constitutive equation derived from a previous statistical analysis of the marker data. The modeling results show that the measurements also can be reproduced satisfactorily from a quantitative viewpoint, and they indicate that an efficient marker installation requires that the monitored depth interval be made mostly from an entirely depleted sandy unit, with the markers placed possibly far from a producing well and approximately 10.5 m apart (i.e., the distance between the gamma ray detectors that monitor the marker position). The cM constitutive law used in the numerical analysis is realistically accurate from 2500 to 3000 m depth, while it appears to be underestimated by a factor of 2 between 800 and 1500 m. The measured expansions allow for the assessment of the reservoir cM under unloading conditions. This turns out to be 2.5 times smaller than cM in virgin loading conditions.
It is well understood and universally recognized that reservoir compaction caused by fluid (water, oil, and gas) production is a major cause for land subsidence of anthropogenic origin. The impact of this occurrence on the stability of low-lying coastal areas has become a matter of great concern worldwide, irrespective of the fluid withdrawn.1–8 Furthermore, field deformation can create minor but nevertheless important operational problems such as failure of well casings, damage to offshore platforms,9 decreased formation porosity or permeability,10 and (hence) a reduction of the field production life.11,12
An important issue is the monitoring of the ongoing in-situ compaction, especially at the early stage of field development, which can help predict the main environmental and technical consequences of fluid withdrawal. For shallow formations down to 500 m (as is typically the case with the water table and confined aquifers used for groundwater pumping), extensometers can be used to effectively measure the porous-system compaction that usually coincides with the ground surface settlement.13 For deeper gas/oil reservoirs, RMT can be used.
The RMT records allow for a straightforward geomechanical characterization of the deformation properties of the porous medium through the evaluation of the uniaxial vertical rock compressibility cM, which is the basic parameter controlling the anthropogenic land subsidence over and around the field both during its production life and after its abandonment.7
When fluid extraction occurs from a deep reservoir, extensometers cannot be used. At the same time, the field compaction does not simply migrate to the ground surface. Generally, a 2D or 3D mathematical model is needed to convert the field compaction into the right fraction of land settlement.14
A pioneering application of radioactive bullets for in-situ compaction measurement was made in the Wilmington oil field, California, as early as 1949,15 but the RMT as it is known today was originally developed for the Groningen gas field in The Netherlands16 and has been continuously improved since then. More recently, RMT has been implemented in the North Sea,17 The Netherlands,18 the Gulf of Mexico,19 and the Northern Adriatic.20 The nominal RMT precision is 10–4 (i.e., 1 mm for a 10-m length of monitored depth interval). However, the real accuracy of measurement depends on the field and porous-medium conditions and is higher in unconsolidated basins, in which deformation is generally larger.21 As an example, in the Gulf of Mexico19 the RMT precision is on the order of 3×10–4.
Over the past 10 years, RMT has been used by Eni-E&P, the Italian national oil company, to record the compaction of a few gas fields in the Northern Adriatic basin, in which several reservoirs are currently being developed.7,14,22 Unfortunately, the structural setting of the Northern Adriatic basin has made the interpretation of the marker measurements particularly difficult. This is partly because of the vertical heterogeneity over a scale that is smaller (and in some boreholes, much smaller) than the RMT scale of monitoring (equal to 10.5 m). As a major result, the interpretation of the marker data from three wellbores instrumented in 1992-96 by Eni-E&P requires an ad hoc nonstandard analysis to derive the deformation properties of the basin. This analysis is herein performed with the aid of a 3D axisymmetric coupled poroelastic model solved by FEs over the scale of the vertical reservoir heterogeneity, as observed from the well logs [e.g., the Stratigraphic High Resolution Dipmeter Tool (SHDT)* and the Electromagnetic Attenuation Propagation Tool (EATT)*].
The objectives of the present analysis are many-fold:
To simulate the marker measurements with an FE mesh resolution consistent with the very detailed heterogeneous lithostratigraphy of the Eni-E&P monitoring boreholes.
To indicate the measurements that represent reservoir compaction and that can be reliably related to the recorded pore-pressure decline and used to obtain representative cM values at the depth of burial.
To reproduce those observed expansions that are unrelated to the flow field recovery, thus providing evidence that the monitored depth interval can expand despite the incorporation of depleted producing layers.
To simulate the expansions actually induced by a pore-pressure recovery and to calibrate a representative cM value in unloading conditions to be used for the prediction of the ground-surface rebound expected over the field after the cessation of gas pumping and the abandonment of the field.