Osijek-Baranja County

Sour-Gas-Reservoir Exploitation in Croatia

Hrncevic, L.. (University of Zagreb) | Simon, K.. (University of Zagreb) | Kristafor, Z.. (University of Zagreb) | Malnar, M.. (University of Zagreb)

OnePetroJune, 2011

Summary Because fossil fuels are still dominant sources of energy supply, the petroleum industry is called upon not only to provide an effective management of oil and gas reserves in order to meet rising energy demand, but also to do that in a safe and efficient manner, with as small an ecological footprint as practically possible. Consequently, also taking into account the fact that conventional oil and gas reserves are declining, petroleum companies are forced to develop and adopt new technologies to increase oil and gas recovery and to expand their upstream activities to still unexploited areas, which often implies development of deep-buried oil and natural-gas reservoirs characterized by unfavorable reservoir conditions such as high temperature and pressure and even a certain amount of impurities. Croatian experience with natural-gas production from deep-buried reservoirs is based on the development of several gas fields in the northwestern part of Croatia. The development of the largest natural-gas fields in Croatia—Molve, Stari Gradac, and Kalinovac gas fields—began at the beginning of the 1980s. The main characteristic of all the mentioned fields are extremely unfavorable reservoir conditions, with reservoir depth of more than 3000 m, high initial reservoir pressures (more than 450 bar), high temperature (180°C), and a significant share of CO2 (10 to 54%), H2S (800 ppm), and some other nonhydrocarbon compounds such as mercaptans (30 mg/m) and mercury (1000 to 1500 μg/m). Several other gas fields with similar reservoir conditions were discovered and developed in the last 25 years in the same region. Today, the petroleum industry in Croatia has almost 30 years of experience in processing sour natural gas with a well-established methodology of auditing processing-plant outlet-gas influences on the environment. These experiences and future plans regarding this subject will be presented in this paper.

OnePetro

doi: 10.2118/132153-PA

SPE

SPE-132153-PA

SPE Projects, Facilities & Construction

Country:

Europe > Croatia > Virovitica-Podravina County (0.90)
Europe > Croatia > Osijek-Baranja County (0.90)
Europe > Croatia > Međimurje County (0.90)
Europe > Croatia > Koprivnica-Križevci County (0.90)

Geologic Time: Phanerozoic (0.95)

Industry:

Energy > Oil & Gas > Upstream (1.00)
Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.68)

Oilfield Places:

Europe > Croatia > Virovitica-Podravina County > Pannonian Basin > Drava Depression > Molve Field (0.99)
Europe > Croatia > Virovitica-Podravina County > Pannonian Basin > Drava Depression > Kalinovac Field (0.99)
Europe > Croatia > Pannonian Basin > Stari Gradac Field (0.99)
(8 more...)

SPE Disciplines:

Reservoir Description and Dynamics > Unconventional and Complex Reservoirs (1.00)
Reservoir Description and Dynamics > Reservoir Characterization (1.00)
Reservoir Description and Dynamics > Reserves Evaluation (1.00)
(5 more...)

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Long-Lasting Experience In Environmental Protection During Sour Gas Reservoir Exploitation

Hrncevic, L.. (University of Zagreb, Faculty of Mining, Geology and Petroleum Engineering) | Simon, K.. (University of Zagreb, Faculty of Mining, Geology and Petroleum Engineering) | Kristafor, Z.. (University of Zagreb, Faculty of Mining, Geology and Petroleum Engineering) | Malnar, M.. (University of Zagreb, Faculty of Mining, Geology and Petroleum Engineering)

OnePetroJanuary, 2010

Abstract Since fossil fuels are still dominant sources of energy supply, in order to meet rising energy demand, petroleum industry is called upon not just to provide an effective management of oil and gas reserves, but also to manage to do that in safe and efficient manner with as low as practically possible ecological footprint. Consequently, also taking into account the fact that conventional oil and gas reserves are declining, petroleum companies are forced to develop and adopt new technologies to increase oil and gas recovery and to expand their upstream activities to still unexploited areas which often implies development of deep- buried oil and natural gas reservoirs characterized with unfavourable reservoir conditions such as high temperature and pressure and even certain amount of impurities. Croatian experience with the natural gas production from deep- buried reservoirs is based on the development of several gas fields in the north- western part of Croatia. The development of the largest natural gas fields in Croatia, Molve, Stari Gradac and Kalinovac gas fields has begun at the beginning of the 1980's. The main characteristic of all the mentioned fields are extremely unfavourable reservoir conditions with reservoir depth over 3000 m, high initial reservoir pressures (over 450 bar), high temperature (180°C) and significant share of CO2, (10 - 54%) H2S (800 ppm) as well as some other non- hydrocarbon compounds like mercaptans (30 mg/m) and mercury (1000 - 1500 µg/m). In the last 25 years in the same region several other gas fields with the similar reservoir conditions were discovered and developed. Today, petroleum industry in Croatia has almost 30 years of experience in processing sour natural gas with well established methodology of auditing processing plant outlet gas influences on the environment. These experiences and future plans regarding this subject will be presented in this paper.

OnePetro

doi: 10.2118/132153-MS

SPE

SPE-132153-MS

SPE Deep Gas Conference and Exhibition

Country:

Europe > Croatia > Virovitica-Podravina County (1.00)
Europe > Croatia > Osijek-Baranja County (1.00)
Europe > Croatia > Međimurje County (1.00)
Europe > Croatia > Koprivnica-Križevci County (1.00)

Geologic Time: Phanerozoic (0.95)

Industry: Energy > Oil & Gas > Upstream (1.00)

Oilfield Places:

Europe > Croatia > Virovitica-Podravina County > Pannonian Basin > Drava Depression > Molve Field (0.95)
Europe > Croatia > Osijek-Baranja County > Pannonian Basin > Drava Depression > Molve Field (0.95)
Europe > Croatia > Međimurje County > Pannonian Basin > Drava Depression > Molve Field (0.95)
(8 more...)

SPE Disciplines:

Reservoir Description and Dynamics > Unconventional and Complex Reservoirs (1.00)
Reservoir Description and Dynamics > Reserves Evaluation (1.00)
Production and Well Operations > Production Chemistry, Metallurgy and Biology > Corrosion inhibition and management (including H2S and CO2) (1.00)
(4 more...)

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Uniquely Engineered Water-Base High-Temperature Drill-In Fluid Increases Production, Cuts Costs in Croatia Campaign

Soric, Tomislav (INA Naftaplin) | Huelke, Robert (M-I Drilling Fluids) | Marinescu, Pavel (M-I Drilling Fluids)

OnePetroFebruary, 2003

Abstract Along with exorbitant costs and safety considerations, drilling in a high-temperature, high-pressure (HTHP) environment also poses the difficult challenge of protecting a reservoir that is all-too-often depleted. In areas where environmental restrictions and compatibility issues in gas fields prohibit the use of an oil-base drilling fluid, engineering a water-base fluid system that is free of potentially damaging solids, stable at very high temperatures, and able to withstand acid gases (CO2, H2S) or other contaminants is a very difficult proposition. The demands are compounded dramatically when drilling a deviated or a re-entry deviated slim hole well in an HTHP environment. Furthermore, since pressure and temperature heavily influences the rheological behavior, it is extremely difficult to calculate, predict and control pressure losses, ECD, and/or ESD in real time to avoid total losses or kicks. This paper details the design of a unique water-base reservoir drill-in fluid and its successful application on five HTHP wells in the Kalinovac and Molve gas fields of Croatia. Four of the wells were high-angle re-entry slim holes. Using laboratory, field, reservoir investigation and computer data, the authors will demonstrate the effectiveness of the new fluid in delivering zero skin damage and subsequently higher production rates than other wells in the field. Further, the system significantly reduced operating costs by eliminating costly stimulations, while simplifying the generation of clear imaging logs. The system also remained stable at bottom hole temperatures of 180 - 200°C. During the drilling operations, a unique software program was employed that accurately predicted the rheological behavior, pressure losses, ECD and ESD, which contributed heavily to the wells being drilled trouble-free. The authors will detail the formulation of the new system, along with the coordination and pre-planning that contributed to its success in Croatia. The new water-base system has shown the effectiveness in drilling HTHP wells in areas where invert-emulsion drilling fluid systems are prohibited. Introduction The Kalinovac/Molve fields are located in northern part of Croatia close to the Hungarian border. Many gas wells have been drilled starting in the early 1970's. Kalinovac/Molve is an example of HTHP conditions with the main reservoir, the dolomitic breccia, exhibiting a pressure of over 400 bars (> 1.4 bars/10 m) and a static bottom hole temperature (BHT) of 180 - 200°C (Figs. 1 and 2). During this project four deviated re-entries were drilled in the Kalinovac field and one vertical well in the Molve field. Typically, these wells have been drilled to a depth of 3,400 - 3,750 m at angles between 0 to 40° (Table 1). The previous wells have been drilled with conventional water-based drilling fluids using a vertical well design. After many years of production the reservoir pressure dropped extensively and the wells encountered water-coning problems. In order to increase production rate and reduce water cut, plans were made to further develop the field. Faced with the options of either drilling new wells or sidetracking existing wells, the operator chose to start a project for deviated re-entries. The main feature of these wells was slim hole drilling into high-temperature depleted reservoirs while potentially encountering lenses still at original pore pressure. The high-pressure difference between the depleted zones and sections of virgin pore pressure created an extremely narrow hydraulic window for the drilling fluid to operate within when drilling the 3 3/4-in. section. Towards this end, the water-based reservoir drill-in fluid was designed to meet the criteria necessary to fulfill this challenge. The fluid had to have optimum rheological profile to provide sufficient hole cleaning, while simultaneously avoiding excessive equivalent circulating densities (ECD's), which would exceed the fracture gradient. The gel structure had to be adequate for solids suspension during static periods, but not so high as to cause excessive pressures when breaking circulation - a condition that could lead to formation breakdown. For safety reasons (the reservoir contains about 70 ppm H2S) H2S-scavengers had to be included. The drilling fluid had both to withstand acid gases (reservoirs contain between 10 and 20 vol-% CO2) as well as to remain stable even when left at BHT's for over 100 hours without circulation during tool changes or logging operations. Overall, the fluid had to be designed for maximum reservoir protection.

OnePetro

doi: 10.2118/79839-MS

SPE

SPE-79839-MS

SPE/IADC Drilling Conference

Country:

Europe > Croatia > Virovitica-Podravina County (1.00)
Europe > Croatia > Osijek-Baranja County (1.00)
Europe > Croatia > Međimurje County (1.00)
Europe > Croatia > Koprivnica-Križevci County (1.00)

Industry: Energy > Oil & Gas > Upstream (1.00)

Oilfield Places:

Europe > Croatia > Virovitica-Podravina County > Pannonian Basin > Drava Depression > Molve Field (0.89)
Europe > Croatia > Virovitica-Podravina County > Pannonian Basin > Drava Depression > Kalinovac Field (0.89)
Europe > Croatia > Osijek-Baranja County > Pannonian Basin > Drava Depression > Molve Field (0.89)
(5 more...)

SPE Disciplines: Well Drilling > Drilling Fluids and Materials > Drilling fluid selection and formulation (chemistry, properties) (1.00)

Technology: Information Technology (1.00)

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Water Shutoff in Extremely Hostile Environment: An Experimental Approach in

Krilov, Z. (INA-Naftaplin) | Tomic, M. (INA-Naftaplin) | Mesic, I. (INA-Naftaplin) | Domitrovic, D. (INA-Naftaplin) | Myers, R.R. (Clearwater, Inc.)

OnePetroApril, 1998

Abstract Based on case history and laboratory research, this paper documents the efforts made to date to solve the problem of excess water production in the large gas condensate fields located in the southwestern part of Pannonian Basin Croatia. According to laboratory studies, a polymer-gel system could be an applicable method to shut off water production in reservoirs characterized as extremely hostile (ultra-high downhole temperature, geologically complex payzone and sour gas, rich with CO). Phenol-formaldehyde crosslinked gels appear to be the most promising for use under such harsh conditions. Long-term stability during in vitro tests, and selective rock permeability reduction during core flooding tests have been achieved at 180C. The problem of retarding the gelation time at reservoir conditions has to be further investigated prior to performing the water shutoff treatment on a candidate gas condensate production well. P. 225

OnePetro

doi: 10.2118/39676-MS

SPE

SPE-39676-MS

SPE/DOE Improved Oil Recovery Symposium

Country:

North America > United States (1.00)
Europe > Croatia > Virovitica-Podravina County (0.28)
Europe > Croatia > Osijek-Baranja County (0.28)
(2 more...)

Geologic Time: Phanerozoic (0.69)

Industry: Energy > Oil & Gas > Upstream (1.00)

Oilfield Places:

Europe > Slovakia > Pannonian Basin (0.99)
Europe > Serbia > Pannonian Basin (0.99)
Europe > Romania > Pannonian Basin (0.99)
(10 more...)

SPE Disciplines:

Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Gas-condensate reservoirs (1.00)
Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
Reservoir Description and Dynamics > Improved and Enhanced Recovery (1.00)
Production and Well Operations > Production Chemistry, Metallurgy and Biology (1.00)

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[8]P1 Twelve Years Experience in Gas Production on the Molve, Kalinovac and Stari Gradac Fields

Zelle, M., Mlinaric, Z.

OnePetroMay, 1994

Abstract. The article covers the production technology as well as the Molve, Kalinovac and Stari Gradac gas fields completion. Specified are the upgrading phases and methods of well completion, from the standpoint of production process optimization and safety, with special accent on the selection of adequate high-alloy steel grades for prevention of the corrosion processes. Experience achieved in the past twelve years has shown that the choice was correct, considering the applied materials as weil as the sealing components and the gas-tight thread joints. No evident damage due to corrosion or any other cause was detected in the past period and we hope that in the majority of cases this will be maintained during the gas wells production life. 1. INTRODUCTION The Molve Gas Field was discovered twenty years ago. Further reservoir engineering was effected seven years later due to extremely severe natural conditions (see Fig. 1). Such conditions were a great challenge at the time, not only for our company, but also for international experts and technologists, and particularly for subsurface and surface well equipment material manufacturers. The first two production wells on the Molve field were equipped and put to production in 1980, after which both reservoir engineering and well construction were intensified, resulting in the completion of the total of 21 wells presently in production, yielding of 200000 to 500000 cubic meters of gas per well daily. The development of the Kalinovac Gas Field began in 1984, and today, there are 14 wells in production, yielding 100000 to 200000 cubic meters of gas per well daily, together with about 120-180 cubic meters of condensate. As can be seen from Table 1, it is a gas-condensate field with extremely severe natural conditions. The Stari Gradac field is the last one in the engineering sequence, covering only 6 completed wells, 3 of them currently in production yielding 50000 to 100000 cubic meters of gas per well daily and 45-85 cubic meters of condensate. Considering the high reservoir pressures, and, especially, high reservoir temperatures, it was necessary to choose the most rational and the safest production completion as well as to conceive the most rational gathering system. We should also .stress the fact that, just recently, the total production of the said three fields amounted to ten billion cubic meters of gas and over two million tons of condensates. 2. GEOLOGY The Molve, Kalinovac and Stari Gradac gas fields are located in the north-western part of Croatia, some 120 km from the capital-Zagreb. Morphologically speaking, it is a low-lying region of the Drava Valley, with an average height of 120 m above sealevel. The ‘Molve’ structure is an asymmetrical anticline cut through its northern part by three reverse fractures. The fluid bearing rocks ar

OnePetro

WPC

WPC-26182

14th World Petroleum Congress

Country:

Europe > Croatia > Virovitica-Podravina County (1.00)
Europe > Croatia > Osijek-Baranja County (1.00)
Europe > Croatia > Međimurje County (1.00)
(2 more...)

Geologic Time: Phanerozoic (1.00)

Industry: Energy > Oil & Gas > Upstream (1.00)

Oilfield Places:

Europe > Croatia > Virovitica-Podravina County > Pannonian Basin > Drava Depression > Molve Field (0.95)
Europe > Croatia > Virovitica-Podravina County > Pannonian Basin > Drava Depression > Kalinovac Field (0.95)
Europe > Croatia > Osijek-Baranja County > Pannonian Basin > Drava Depression > Molve Field (0.95)
(6 more...)

SPE Disciplines:

Well Completion > Completion Selection and Design > Completion equipment (1.00)
Well Completion > Completion Installation and Operations (1.00)
Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Gas-condensate reservoirs (1.00)
(8 more...)

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Completion and Testing of the 242C BHST Well Dinjevac-1

Uroda, Pavle (Baker Sand Control) | Rogoz, Luka (INA-Naftaplin) | Sinovcevic, Zeljko (INA-Naftaplin) | Kovac, Darko (INA-Naftaplin)

OnePetroSeptember, 1992

Summary Well Dinjevac-1 (Di-1), located 120 km northeast of Zagreb, Croatia, was drilled in 1982 to a total depth (TD) of 5502 m. Mud logs, electrical logs, and drillstem tests (DST's) in the Miocene section of the Pannonian basin indicated hydrocarbon saturation, extremely high temperatures, and relatively high pressures. These Miocene sediments are characterized as compact, low-permeability sandstones. In 1988, the abandoned cement plugs were drilled out and a bottomhole static temperature (BHST) of 242C was measured. Temperature was the critical factor in the design of the completion and testing method. In spite of some minor quality-control and operational problems, five zones were tested successfully, providing all the relevant information about the reservoirs and the formation fluids. The operation incorporated a one-trip, hydraulically set, high-temperature, high-differential packer with a polished-bore receptacle and tubing-conveyed perforating guns with large, deep-penetrating charges. This paper describes the completion and testing objectives, considerations, operations, and results under probably the hottest completion conditions ever encountered. Introduction The hydrocarbon reservoirs of the Pannonian basin, well-known for its large temperature gradient, I have been explored intensively in shallow and medium-depth formations in Hungary and Croatia. Drilling and especially testing of deeper formations, such as Deep Tertiary, were unsuccessful in the past because the technology for working in extrahot (greater than 200C) environments was limited. Limitations included the functional reliability of the drilling and completion fluids, elastomers, lubricants, instruments, and perforating explosives. In the 1980's, oil companies intensified perforating explosives. In the 1980's, oil companies intensified their search for energy sources by drilling zones below 4000 m. Well Or-2 was drilled to a TD of 6102 m. In 1987, a test of the zone at 5540 m was attempted with conventional ball-type testing tools and a retrievable mechanical packer. A temperature of 232C was recorded at 5540 m. For the test, the well was circulated to cool down the wellbore before the through-tubing perforating operation. The test failed because all the elastomers in the downhole tools burned and all the lubricants and greases degraded. When drilled, Well Di-1 was too hot for the commercially available technology of the early 1980's. Hence, testing was postponed. The recent Duboka Drava project (a deep drilling exploration project where a number of wells have bottomhole conditions similar to those of Well Di-1) rekindled the interest in defining possible concepts for completion and testing in such environments. Given the well conditions (multiple zones characterized as extrahigh-temperature, high-pressure, and tight), completion and testing would require a single-run test/completion/perforating string that would allow for tubing movement during stimulation. Additionally, a retrievable, instead of a permanent, system would be required if milling should become necessary. Geology and Drilling History Well Di-1 is located in the Bilogora section of the Drava depression of the Pannonian basin. It is 7 km south of the largest Croatian gas-condensate field, Kalinovac. Its location is related to the Molve-Kalinovac-Stari Gradac line south of the main fault on the Pitomaca brachianticline structure in Miocene sediments (Fig. 1). Well Di-1 was drilled to define potential hydrocarbon reservoirs in the Miocene. A 339.7-mm intermediate casing string was set just above the pressure transition (Fig. 2). Overpressure was recorded from 2400 m to TD with a maximum overpressure of 147 kPa/10 m at 2670 m. A 244.5-mm intermediate casing string and a 139.7-mm liner were required to reach TD. The well encountered three drilling problems related to the subsequent completion and testing operations: damage to the 244.5-mm casing from potential helical buckling, washouts in the 215.9-mm openhole section, and extreme temperatures. Stress analysis of the 244.5-mm casing during the running, cementing, and subsequent drilling operations indicated that the lower section of this intermediate string was exposed to potential helical buckling (Fig. 3).

OnePetro

doi: 10.2118/20905-PA

SPE

SPE-20905-PA

SPE Drilling Engineering

Country:

Europe > Croatia > Zagreb County > Zagreb (0.26)
Europe > Croatia > Virovitica-Podravina County (0.24)
Europe > Croatia > Osijek-Baranja County (0.24)
(2 more...)

Geologic Time: Phanerozoic > Cenozoic > Neogene > Miocene (0.85)

Industry:

Energy > Oil & Gas > Upstream (1.00)
Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.56)

Oilfield Places:

Europe > Slovakia > Pannonian Basin (0.99)
Europe > Serbia > Pannonian Basin (0.99)
Europe > Romania > Pannonian Basin (0.99)
(3 more...)

SPE Disciplines:

Well Drilling > Drilling Operations (1.00)
Well Drilling > Casing and Cementing > Casing design (1.00)
Well Completion > Completion Installation and Operations > Perforating (1.00)
(2 more...)

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Fracturing of High-Temperature, Naturally Fissured, Gas-Condensate Reservoirs

Cikes, Marin (INA-Naftaplin) | Economides, Michael J. (Mining U. Leoben)

OnePetroMay, 1992

Summary Eleven hydraulic fracture treatments were performed in deep (3300 to 3800 m[10,830 to 12,470 ft]), extremely high temperature (180 to 195 C [356 to 383OF]), naturally fissured, gas-condensate reservoirs. Formation permeabilitiesat the fractured well locations range from 0.003 to 0.2 md, permeabilities atthe fractured well locations range from 0.003 to 0.2 md, while the initialformation pressure gradient is about 0.13 bar/m [0.57 psi/ft]. The producingfluid is high-gravity gas (0.83 to 1.15 to air) and psi/ft]. The producingfluid is high-gravity gas (0.83 to 1.15 to air) and contains up to 22% CO2 andup to 4% H2S. Job sizes have ranged from 300 to 2000 m3 [80,000 to 528,400 gal]of fluid and 50 to 600 Mg [110,130 to 1,321,590 Ibm] of high-strength proppant. This paper emphasizes the general approach to well completion and stimulationtreatment design, treatment execution, and evaluation. Interesting itemsinclude the engineering of the fracturing fluids to sustain their viscosity atthe extreme temperatures and to reduce leakoff in these highly fissuredformations. An outline of the reservoir description is also given. Posttreatment well production has been excellent in most cases. Well Pi'sincreased from 0.01 to 0.6 m3/d bar2 [0.0017 to 0.1 scf/D-psi] to 0.235 to 7.83m3/d bar2 [0.04 to 1.3 scf/D-psi2]. Treatment results suggest that leakoff canbe controlled with particulate agents, that delayed crosslinking is the onlyway to execute particulate agents, that delayed crosslinking is the only way toexecute these treatments, and that hydraulic fracturing can greatly improve theproduction from naturally fissured formations. Fracture design and theproduction from naturally fissured formations. Fracture design and thepredicted well production are compared with post-treatment performances inpredicted well production are compared with post-treatment performances inselected wells. Introduction After the successful execution and subsequent improved performance of amodest hydraulic fracture treatment in a high-temperature performance of amodest hydraulic fracture treatment in a high-temperature gas-condensate well, it became obvious that a much longer hydraulic fracture was indicated. Thisconclusion was based on the apparent reduction of reservoir permeability causedby the emergence of gas condensate and on the fact that a finite conductivityhydraulic fracture, producing in a fissured formation, exhibits an apparent(effective) length significantly smaller than the real length. Both reasonspoint to the necessity of performing large hydraulic fractures in suchformations. Massive hydraulic fracturing has proved to be the most successfultechnique to improve the productivity of tight gas sands. Deeply penetratingfractures can substantially improve well productivity and ultimate recovery tothe point where uneconomical wells productivity and ultimate recovery to thepoint where uneconomical wells can become profitable. Many works haveillustrated the merits of obtaining long, highly conductive fractures inlow-permeability reservoirs. However, most of these publications deal withmoderate temperature, homogeneous, and (probably) isotropic sandstoneformations. Except for geothermal wells, few high-temperature >180deg.C[>356deg.F]) case histories of hydraulic fractures have been discussed. Thewell-known constant-height, ideal-fracture-geometry models, which assumehomogeneous, isotropic media, may not be applicable in anisotropic, naturallyfissured reservoirs. Other models could be more appropriate in such asituation, as indicated by the analysis of abnormal treating pressures observedduring hydraulic fracture treatments. Some published case studies of fracturingin highly anisotropic formations show not only difficulties with the executionof hydraulic fracturing, but also poor improvement of well productivity. Withthat in mind, we designed and performed Il hydraulic fracture treatments indeep [3300 to 3800 m [10,830 to 12,470 ft]), extremely high-temperature (180 to195deg.C 1356 to 383deg.F]), naturally fissured, gas-condensate reservoirs. Anoverview of these treatments suggests certain answers to questions posed in theliterature. Treatment Considerations The treatments were done in specific formations of three differentreservoirs: Molve, Kalinovac, and Stari Gradac. These reservoirs are located innorth Croatia, close to the Hungarian border, and constitute the main part ofthe Drava depression of the Pannonian basin (Fig. i). Geological and physicalproperties of the Kalinovac field are described in Refs. 1 and 18, while Ref.19 gives a more complete geologic description of the Drava depression. In thisstudy, the reservoir rocks were represented by the following.Devoniancarbonate schists of pronounced fracture porosity and permeability. lower Triassic quarizites/metarenites with distinct microfractures and vuggyporosities. Middle Triassic, early diagenetic, extraordinarily anisotropicdolomites (with almost vertical fractures) from the Molve and Kalinovac fields, and coarse clastic rocks from reservoir formations at the Stari Gradac field. Lower Jurassic, late diagenetic, molitic dolomite from the Molve field only. Miocene carbonate facies (grainstone, wackstone, packstone-typelithotharnian limestone) only from the Molve field. The packstone-typelithotharnian limestone) only from the Molve field. The Kalinovac field, whichis of the same age, is represented by clastic rocks of low flow capacities. Thesame clastic rocks contain no hydrocarbons at the Stari Gradac field. Triassicand Jurassic dolomites have strongly pronounced anisotropic properties. Theyare characterized by an exceptional number of fractures of thesouth-southwestern slope and strike parallel to the main tectonic lines.parallel to the main tectonic lines. In such reservoirs, hydraulic fracturingmay not be successful. Regardless of the origin and geological history of thefissures and natural fractures, the current state of stresses influences theirdisribution and orientation. Because stresses are compressive in nature, themaximum stress would preferentially close fissures normal to its direction. This would result in a permeability anisotropy with a maximum value in thedirection of maximum stress. This configuration is the least favorable forexpected production increase from the hydraulic fracture. Furthermore, the hopeof connecting natural fractures, which generally follow the general trend ofthe manmade fracture, may not be realized to any appreciable degree. Anyintersection of natural fractures by the hydraulic fracture, however, createsunique problems during execution because of the presence of discontinuitiesthat may affect the propagation path of presence of discontinuities that mayaffect the propagation path of the induced fracture and high leakoff caused bythief fissures. Warpinski and Teufel considered the effect of geologicaldiscontinuities on the propagation of a hydraulic fracture, giving criteria forthe fracture to alter its direction. if treating pressures are large enough, shear slippage may be induced along joint or fissure sets. Jeffrey et al. analyzed the condition for effective proppant transport in those situations. When proppant bridging is present, the resulting increase in treating pressuresmay iced to dendritic fracturing. Kiel discussed the advantages of the createdconnected pattern, which results in volume drainage vs. the classic arealdrainage created by a planar fracture.

OnePetro

doi: 10.2118/20973-PA

SPE

SPE-20973-PA

SPE Production Engineering

Country:

North America > United States > Texas (1.00)
Europe > Croatia > Virovitica-Podravina County (1.00)
Europe > Croatia > Osijek-Baranja County (1.00)
(2 more...)

Genre: Research Report > New Finding (0.34)

Geologic Time: Phanerozoic > Mesozoic > Triassic (1.00)

Industry: Energy > Oil & Gas > Upstream (1.00)

Oilfield Places:

Europe > Croatia > Virovitica-Podravina County > Pannonian Basin > Drava Depression > Molve Field (0.99)
Europe > Croatia > Virovitica-Podravina County > Pannonian Basin > Drava Depression > Kalinovac Field (0.99)
Europe > Croatia > Pannonian Basin > Stari Gradac Field (0.99)
(6 more...)

SPE Disciplines:

Well Completion > Hydraulic Fracturing > Fracturing materials (fluids, proppant) (1.00)
Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Gas-condensate reservoirs (1.00)
Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)

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

Economides, Michael J. (Dowell Schlumberger) | Cikes, Marin (INA-Naftaplin) | Pforter, Harry (Dowell Schlumberger) | Udick, Thomas H. (Dowell Schlumberger) | Uroda, Pavle (INA-Naftaplin)

OnePetroMarch, 1989

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.

OnePetro

doi: 10.2118/15239-PA

SPE

SPE-15239-PA

SPE Formation Evaluation