The Stimulation of a Tight, Very-High-Temperature Gas-Condensate Well

Abstract

Summary. Well KAL-5, completed in the Moslavacka Gora formation of the Pannonian basin in Yugoslavia, was tested at a flow rate of 75 Mscf/D [2124 std m3/d] of gas and 2.8 B/D [0.45 m3/d] of condensate and at a last bottomhole pressure (BHP) of 1,083 psi [7.5 MPa]. Pretreatment evaluation determined a reservoir permeability in the 0.003- to 0.004-md range. The high formation temperature (354 deg. F [179 deg. C]) poses problems for most fracturing fluids. This paper presents a pretreatment analysis of the well, its geologic setting, and thermal and lithological characteristics as they relate to the choice of the fracturing-fluid system. An outline of the stimulation design and execution is included. After a modest hydraulic fracture treatment, the well flowed for 21 days at a last flow rate of 1,925 Mscf/D [55 × 10 std m3/d] of gas and 117 B/D [18.7 m3/d] of condensate at a flowing BHP of 912 psi [6.3 MPa]. This substantial increase was apparently caused by the successful hydraulic fracture; geometric features of the fracture were estimated from interpretation of a posttreatment well test. Posttreatment evaluation assesses the effectiveness of the job, calculates the geometric dimensions and the conductivity of the fracture, and presents forecasts of future performance. Finally, the effects of the evolved gas condensate on the reduction of the apparent reservoir permeability are investigated and evaluated. A correlation between pressure, in-situ condensate saturation, and permeability is offered. Introduction The Kalinovac field is a gas-condensate reservoir located near Durdevac in north Yugoslavia, close to the Hungarian border. Since its discovery in the late 1970's, the Kalinovac field, which is part of the main zone of the Drava depression of the Pannonian basin, has proved to be the most important hydrocarbon-producing area of Yugoslavia. The area and its general lithology are shown in Fig. 1. The field is the central structure of the Molve-Kalinovac-Stari Gradac line. The Kalinovac field occupies a 6.2x2.5-mile [10x4-km] area. As in the Molve field, quantities of H2S and CO2 are found in the producing fluid. These gases influence the cost of drilling and well completion operations. Besides the hostile environment, very high temperatures in the formation (356 deg. F at 11,500 ft [180 deg. C at 3500 m]) make well completions, and particularly stimulation activities, cumbersome. Fracturing hot and deep formations, a reasonably new process, has been made possible through the introduction of transition-metal crosslinkers that enhance the viscosity of water-based polymer solutions. Titanium and zirconium complexes have been used frequently because the bond formed between them and the polymer is very thermally stable. Very hot wells (greater than 400 deg. F [greater than 204 deg. C]) have been fractured with these fluids. Therefore, the fracturing of Well KAL-S should not have posed problems from the job-execution point of view. Of particular interest, though, was the heavy condensate nature of the gas. Production and the created pressure gradient within the reservoir result in a liquid-condensate gradient that leads to a significant reduction in the effective permeability to gas. In fact, this liquid accumulation usually results in permanent "damage," and no recovery of the flow rate is realized in a new drawdown following a buildup. This "hysteresis" phenomenon, for gascondensate wells, has been described by Fussel, and a testing procedure for heavy-gas-condensate wells was presented by Economides et al. No case studies of fractured heavy-condensate wells have been reported in the literature. Geologic Setting. The Kalinovac structure is composed of an anticline in Paleozoic. Mesozoic, and Lower Miocene sediments with northwest/southeast Dinaric trends. The trap in which the reservoir was formed is of a stratigraphic type associated with a tectonic-erosional unconfomity-i.e., discontinuity (break) of sedimentation between the pre-Tertiary and Lower Miocene sediments. The reservoir was formed in three main stratigraphic sections with significant variations of formation rocks mutually separated by transgressive boundaries. The Paleozoic metamorphic complex, with breccia and schists, is characterized by secondary porosity caused by natural fissures. The porosity of the complex is greater at the top of the structure and disappears toward the deeper parts. The Mesozoic carbonate sediments (limy dolomitic breccias and carbonate breccias) are also characterized by secondary fissure porosity, but existing primary porosity has enabled a substantial hydrocarbon accumulation. The Lower Miocene sediments with heterogeneous lithology (dolomitic breccias and conglomerates. silty fossiliferous sandstones, and marly limestones) are characterized by combined primary and secondary porosities. The overlying rocks, which served as a barrier to further vertical migration of hydrocarbons, consist of impermeable marl of the Pannonian stage. Above this cap is a continuity of Pliocene and Quaternary sediments. Physical Properties of Reservoir Rock and Fluid. The reservoir porosity (obtained from logs) is in the range of 0.054 to 0.076 md in sedimentary rocks and 0.05 md in metamorphic rocks. The mean water saturation varies from less than 0.6 in metamorphic rocks to less than 0.55 in sedimentary rocks. Permeability values obtained from pressure-buildup analyses point toward the need for massive hydraulic fracturing for most parts of the field. In the major part of the reservoir. permeability ranges from 0.5 to 2 md. In the lower part of the structure, permeability is much lower (less than 0.01 md). The formation pressure gradient is about 0.61 psi/ft [13.8 kPa/m], while the fracturing gradient varies between 0.75 and 1.0 psi/ft [17 and 22.6 kPa/m]. The southwest portion of the Pannonian basin, the Drava depression, is characterized by extremely high temperature gradients, as shown in Fig. 2. Based on statistical analysis of numerous measurements in deep wells, this correlation for the prediction of the average formation temperatures as a function of depth was developed by Jelic. For example, for a 10,000-ft [ 3-km] well, a typical reservoir temperature is 3 10 deg. F [ 154 deg. C], resulting in a temperature gradient of 2.4 deg. F/100 ft [4.3 deg. C / 100 m]. The Molve-Kalinovac-Stari Gradac line is in a part of the Drava depression that contains higher-than-average temperature gradients in the range of 2.7 to 3 deg. F /100 ft (5 to 5.5 deg. C /100 m]. The temperature gradient in the Kalinovac structure is 2.85 deg. F/100 ft [5.28 deg. C /100 m]. The reservoir fluid is gas condensate (the GOR is 9,470 scf/STB [1706 std m /stock-tank m3]) with up to 30% CO, and 60 ppm H S. PVT analysis demonstrates that the reservoir fluid forms a single phase, but, as with most other gas-condensate reservoirs, the initial conditions (pi, Ti) coincide with the retrograde condensation point.

Wettability Alteration to Intermediate Gas-Wetting in Gas-Condensate Reservoirs at High Temperatures

“…Because of the low permeability and the wettability characteristics, it may take a long time to perform the cleanup; in some cases, as little as 10 to 15% of the water load could be recovered (Mahadevan and Sharma 2005;Penny et al 1983). Even when the problem of water blocking is not significant, the accumulation of condensate around the fracture face when the pressure falls below dewpoint pressure could result in a reduction in the gas production rate (Economides et al 1989;Sognesand 1991;Baig et al 2005).…”

Well Test Analysis in Gas-Condensate Reservoirs

“…Consequently, many laboratory 5,6,11,12,33 theoretical 1,2,4,9-14 and field investigations 10, [15][16][17][18][19][20][21][22][23] have been conducted over the last forty years to try to understand condensate reservoir flow behavior. It has been found that, when reservoir pressure around a well drops below the dew point pressure, retrograde condensation occurs and three regions are created with different liquid saturations 14,24,25 .…”

Development of inflow performance model in high temperature gas-condensate reservoirs

“…Pseudo critical temperature (Tpc) and pressure (Ppc) proposed by Elsharkawy et al, (2000), which developed for gas condensate reservoirs were also used to model two phase compressibility factor. Transient pressure test data from high temperature heavy gas condensate well was obtained from Economides et al, (1989) and utilized to generate the IPR curves. New IPRs covers effect of condensate blockage near wellbore region as an important factor in reducing well productivity (Behmanesh et al, 2017;Chen et al, 1995;Fevang and Whitson, 1996;Gondouin et al, 1967;Rahimzadeh et al, 2016).…”

“…(17) has been used to calculate pseudopressure function. This is because the well that was selected for this study is producing heavy condensate and is very high in temperature (Economides et al, 1989).…”

“…The validity of the new IPR model is verified by compositional simulation of a high temperature rich gas condensate well, using Schlumberger (PIPSIM) simulator. Results of transient pressure test data is obtained from Economides et al, (1989) Whitson et al, 2000). Table 2 includes fluid molar composition of the reservoir (Economides et al, 1989).…”