Subsurface Temperature Assessment: Improving Reliability of Deep Well Data

Pre-salt carbonates in the Pre-Caspian Basin have prolific hydrocarbon-bearing formations onshore and offshore. Recent exploration wells more than 5000 m deep in the region have had limited success, mostly due to challenging conditions for well testing. This paper summarizes key elements of one of the first successful drill stem testing (DST) campaigns in Ansagan Field. The holistic DST design for Ansagan field addressed perforating methods, brine selection, packer and DST equipments material selection for hostile environment with high-pressure, high-H2S fluids, and corrosive acid to be used for stimulation. The surface equipment design had to reliably control the well, separate fluids, measure flow rates, and dispose hydrocarbons with minimum environmental impact. Surface flow rate measurement combined of a multiphase flowmeter and three-phase separator. Downhole samples were collected with a single-phase reservoir fluid sampler. Calcium & zinc bromide brine with 1.77-SG density proved effective. The specially modified completion packer design was in the well up to 6 months and was successfully retrieved after the test. Although perforating in these deep high pressure wells was usually performed on wireline, accurate shock prediction and design adjustments managed the risk for using tubing-conveyed perforating (TCP) to perforate large intervals in underbalance conditions allowing to achieve lower skin, and flow the well immediately. The DST string enabled performing production logging, downhole fluid sampling, and acid stimulation with coiled tubing. Fluid sampling was performed on wireline to preserve gas condensate components at reservoir conditions. The highly accurate memory gauges, real-time operations, and reservoir engineer's support made it possible to acquire accurate data to characterize the fracture distribution, which is vital information in fractured carbonates. In summary, three wells have been successfully tested with a total of 16 zones at Ansagan field, achieving all well test objectives.

A three-dimensional numerical model to simulate Iranian NW Sabalan geothermal system

Estimation of static formation temperatures in geothermal wells by using an artificial neural network approach

Corrosion problems of deep well tubings and their control measures are discussed. As one of the economical solutions, metal-lined tubings are proposed. It is shown that the metal liner can be tightly fitted by the newly developed thermo-hydraulic fit method. The selection of corrosion-resistant material for the liner is discussed. Some designs of the tubing joint and their manufacturing methods pre proposed. Introduction With the seriousness of an energy shortage, the drillings of oil and gas wells have become more active. In the last few years, the number of drilled wells has increased rapidly as shown in Fig. 1. It should be noted that eighty percent of these wells were drilled in the United States. Fig. 2 shows the depth distribution of oil and gas wells drilled in the United States in 1977. It can be seen that the numbers of oil and gas wells are about the same, but, in general, there are more gas wells at deeper depths than oil wells. As shown in Fig. 3, well depth increases each year, and recently an exploratory well deeper than 10,000 m has been drilled. As the well depth increases, the down hole pressure and temperature rise. For instance, in some severe wells at a depth of 6,000 m, the pressure and temperature are more than 1,000 bar and 200°C respec. tively. Therefore, the strength of the tubings used in such severe conditions is a very important factor for deep wells because they have to sustain their ownweight also. Figure 4 diagrammatically illustrates the transitions of design conditions with the increaseof well depth. Figure 5 shows the relationship between well depth and axial and hoop stresses of API standard tubings with various pipe 'dimensions. It isknown roughly that the strength of class P-I05 is required for the tubing of a 6,000 m well. Another substantial problem in deep oil and gas wells is corrosion. This is mainly due to H2S and C02 which are contained in crude oil and natural gas The density of these contaminants is increased with well depth, and, together with high pressure and high temperature, the corrosion reaction is accelerated. To solve all the above problems in deep wells, a new type of economical, high strength tUbing which has high corrosion resistance is expected. At present a super Ni alloy tubing, which is extremely expensive, tends to be used. As a solution, the authors propose the Tight Fit Tubing (hereinafter referred to as TFT) which is lined inside with corrosion-resistant alloy to meet the above three requirements for the tubing of deep wells. The thermo-hydraulic fit method used here for TFT has been developed to produce the corrosionresistant pipe, TFP, for corrosive flow lines as reported in Ref. 1.

More than 160 heat flow data with different origins have been combined in order to outline the major trends of heat flow in France. The basic data are separated into different groups according to the various characteristics of the measurement and a systematic comparison between each group is attempted. In particular, classical measurements obtained from conductivity determination and temperature logging in shallow boreholes are compared with measurements derived from bottom hole temperature in deep oil exploration wells.

This paper describes optimization of gelled and in-situ gelled HCl/formic acid systems to stimulate deep gas wells completed with super Cr-13 tubing. High temperatures encountered in deep wells and the susceptibility of super Cr-13 to severe corrosion by concentrated HCl solutions and high chloride ion concentrations render acid stimulation a very difficult task. Therefore, extensive experimental and field studies were performed to develop a cost effective acid system to enhance the productivity of deep gas wells, while maintaining the integrity of the super Cr-13 tubing. Coreflood tests indicated that this acid system can create deep wormholes in tight reservoir cores (less than 1 md). Corrosion tests, however, indicated that protecting super Cr-13 tubulars during pumping this acid (15 wt% HCl/9 wt% formic acid) is not an easy task, especially at downhole temperatures (275°F). A very limited number of inhibitor aids were found to be effective in protecting super Cr-13 at reservoir conditions. To optimize the corrosion inhibitor package, the bottom hole temperature was measured in a few wells during acid injection. Based on lab tests and field measurements, an acid treatment was designed and applied in the field. The treated wells responded positively to the treatment. Most importantly, the integrity of the super Cr-13 was maintained. This was confirmed from chemical analysis of well flowback samples following the treatment and measurement of the tubing inside diameter before and after the treatment. The maximum Cr concentration in the flowback sample was less than 2 mg/L. Molybdenum and nickel concentrations were less than 1 mg/L. The total iron concentration was less than 200 mg/L. This value is significantly less than that noted with wells completed with low-carbon steel tubulars.

This paper presents the drilling and completion practices for two deep hot sour gas wells in the Madison formation of the Madden Deep Unit of Wyoming. The wells were drilled to almost 25,000 feet (7625 m). The drilling program, casing program, well test data and completion programs are discussed and compared to other sour gas fields such as Mobile Bay, Alabama. The gas composition, bottom hole pressure and temperature and production rates exceed those in Mobile Bay making the conditions some of the worst in the world. The high bottom hole temperature, and CO2 and H2S content necessitated the use of corrosion resistant alloy (CRA) completions. The CRAs selected and the respective equipment in which they were used are discussed. The analysis and prediction of elemental sulfur precipitation is also discussed.

The Sipoholon Geothermal Field and adjacent geothermal systems along the North-Central Sumatra Fault Belt, Indonesia: Reviews on geochemistry, tectonics, and natural heat loss

Research Article| May 01, 1992 Heat flow and subsurface temperature as evidence for basin-scale ground-water flow, North Slope of Alaska DAVID DEMING; DAVID DEMING 1U.S. Geological Survey, 345 Middlefield Road, M.S 923, Menlo Park, California 94025 Search for other works by this author on: GSW Google Scholar JOHN H. SASS; JOHN H. SASS 2U.S. Geological Survey, 2255 North Gemini Drive, Flagstaff, Arizona 86001 Search for other works by this author on: GSW Google Scholar ARTHUR H. LACHENBRUCH; ARTHUR H. LACHENBRUCH 1U.S. Geological Survey, 345 Middlefield Road, M.S 923, Menlo Park, California 94025 Search for other works by this author on: GSW Google Scholar ROBERT F. DE RITO ROBERT F. DE RITO 1U.S. Geological Survey, 345 Middlefield Road, M.S 923, Menlo Park, California 94025 Search for other works by this author on: GSW Google Scholar GSA Bulletin (1992) 104 (5): 528–542. https://doi.org/10.1130/0016-7606(1992)104<0528:HFASTA>2.3.CO;2 Article history first online: 01 Jun 2017 Cite View This Citation Add to Citation Manager Share Icon Share Facebook Twitter LinkedIn MailTo Tools Icon Tools Get Permissions Search Site Citation DAVID DEMING, JOHN H. SASS, ARTHUR H. LACHENBRUCH, ROBERT F. DE RITO; Heat flow and subsurface temperature as evidence for basin-scale ground-water flow, North Slope of Alaska. GSA Bulletin 1992;; 104 (5): 528–542. doi: https://doi.org/10.1130/0016-7606(1992)104<0528:HFASTA>2.3.CO;2 Download citation file: Ris (Zotero) Refmanager EasyBib Bookends Mendeley Papers EndNote RefWorks BibTex toolbar search Search Dropdown Menu toolbar search search input Search input auto suggest filter your search All ContentBy SocietyGSA Bulletin Search Advanced Search Abstract In conjunction with the U.S. Geological Survey's exploration program in the National Petroleum Reserve, Alaska (NPRA) several high-resolution temperature logs were made in each of 21 drillholes between 1977 and 1984. These time-series of shallow (average 600-m depth) temperature profiles were extrapolated to infinite time to yield equilibrium temperature profiles (±0.1 °C). Thermal gradients are inversely correlated with elevation, and vary from 22 °C/km in the foothills of the Brooks Range to as high as 53 °C/km on the coastal plain to the north. Shallow temperature data were supplemented with 24 equilibrium temperatures (±3-5 °C) estimated from series of bottom-hole temperatures (BHTs) measured near the bottom of petroleum exploration wells. A total of 601 thermal conductivity measurements were made on drill cuttings and cores. Near-surface heat flow (±20%) is inversely correlated with elevation and ranges from a low of 27 mW/m2 in the foothills of the Brooks Range in the south, to a high of 90 mW/m2 near the north coast. Subsurface temperatures and thermal gradients estimated from corrected BHTs are similarly much higher on the coastal plain than in the foothills province to the south. Significant east-west variation in heat flow and subsurface temperature is also observed; higher heat flow and temperature coincide with higher basement topography. The observed thermal pattern is consistent with forced convection by a topographically driven ground-water flow system; alternative explanations are largely unsatisfactory. Average ground-water (Darcy) velocity in the postulated flow system is estimated to be of the order of 0.1 m/yr; the effective basin-scale permeability is estimated to be of the order of 10-14 m2. Organic maturation data collected in other studies indicate that systematic variations in thermal state may have persisted for tens of millions of years. The ground-water flow system thought to be responsible for present heat-flow variations conceivably has existed for the same period of time, possibly providing the driving mechanism for petroleum migration and accumulation at Prudhoe Bay. This content is PDF only. Please click on the PDF icon to access. First Page Preview Close Modal You do not have access to this content, please speak to your institutional administrator if you feel you should have access.

The Chattian Lower Freshwater Molasse (USM) of the Thun area comprises a thick series of continental sediments which occur in three imbricate thrust sheets (Steffisburg, Zulg-Hombach, Blueme) of the Subalpine Molasse and over wide areas of the autochthonous Plateau Molasse. Facies analysis of outcrops, complemented by conglomerate clast counts, sandstone petrography, heavy mineral analysis and data from two deep exploration wells and seismics permit structural restoration of the thrust sheets, correlation of subalpine and autochthonous USM and consequently the reconstruction of the geometry and facies evolution of the alluvial fan systems. The most complete succession measuring more than 4500 m is preserved in the structurally highest Blueme thrust sheet

Technology Update The drillstem test (DST) is one of the oldest methods used to test a formation’s capability to produce hydrocarbons. An early patent filed on drillstem testing in 1926 describes it as a method for “testing the productivity of formations encountered in drilling oil and other deep wells.” While frontiers such as deepwater drilling were far in the future, the industry was already seeking methods and equipment that were more efficient and economical than those in use then. Technology has continued to advance from mechanical openhole testing to modern annulus pressure controlled cased hole drillstem testing. An impressive array of annulus pressure-operated downhole test tools is available and provides operators with versatility and flexibility in drillstem testing. Downhole tool technology has advanced to extreme limits, with tools capable of handling bottomhole conditions of 35,000 psi and 500°F. Meanwhile, drilling technology has also progressed, with wells drilled to greater depths and in deeper water. Operating conditions pose new challenges to cost efficiency and annular pressure limitations. The inherent complexity of deepwater DST operations implies that a significant number of downhole test tools require some form of annular pressure manipulation. Tubing string tester valves, primary and backup circulating valves, bottomhole sampler triggers, and primary and backup firing heads for tubing-conveyed perforating are some examples. In deep water, the maximum allowable casing pressure has become the limiting factor in an increasing number of instances, and this reduces flexibility in designing the downhole test string. Advances in acoustic wireless telemetry have led to a novel and reliable alternative approach to operating downhole test tools in drillstem testing and providing real-time feedback of tool status, bottomhole pressure and temperature, and bottomhole fluid sample conditions. Wireless Telemetry Although wireless telemetry for downhole applications in the oil industry has been used since the 1940s, it did not gain much traction until the 1990s. Different wireless technologies have been studied and tested. Mud pulse telemetry found little use in drillstem testing because of low bandwidth and operational limitations. Electromagnetic telemetry saw some early use but also had limited data transmission capabilities, and the method does not work in subsurface salt layers.

STATIC_TEMP: a useful computer code for calculating static formation temperatures in geothermal wells

Cuttings recovered from two deep exploratory wells in the Lihue Basin, Kauai, Hawaii, include fossiliferous marine deposits that offer an uncommon opportunity to study paleoenvironments from the deep subsurface in Hawaii and interpret the paleogeography and geologic history of Kauai. These deposits indicate that two marine incursions gave rise to protected shallow-water, low-energy embayments in the southern part of the Lihue Basin in the late Pliocene–early Pleistocene. During the first marine incursion, the embayment was initially zoned, with a variable-salinity environment nearshore and a normal-marine reef environment offshore. The offshore reef environment eventually evolved to a nearshore, variable-salinity environment as the outer part of the embayment shallowed. During the second marine incursion, the embayment had normal-marine to hypersaline conditions, which constitute a significant departure from the variable-salinity environment present during the first marine incursion. Large streams draining the southern Lihue Basin are a likely source of the freshwater that caused the salinity fluctuations evident in the fossils from the first marine incursion. Subsequent volcanic eruptions produced lava flows that buried the embayment and probably diverted much of the stream flow in the southern Lihue Basin northward, to its present point of discharge north of Kalepa Ridge. As a result, the embayment that formed during the second marine incursion received less freshwater, and a normal-marine to hypersaline environment developed. The shallow-water marine deposits, currently buried between 86 m and 185 m below present sea level, have implications for regional tectonics and global eustasy.

Technical and Operational Factors Crucial to Successfully Drilling Deep Exploratory Wells

The present study is focused on the subsurface geology of Bannu Basin, a part of western Indus foreland Pakistan. For this purpose, some regional seismic profiles and deep exploratory wells data have been used in integration.A total of ten mappabale seismic reflection events have been identifed which are representative of specific geological units. In general, based on the seismic the formation trends, the horizons are dipping in the northwest direction of the study area. The area generally deepens toward the northwest due to sediments load toward the northwest. The seismic profile MWI-83 shows a unique faults bounded anticlinal structure that has also been mapped on the two-dimmensional contour maps. This could be regarded as potential hydrocarbon entrapment. The regional seismic profiles are contoured for the entire grid in both time and depth domain to obtain the clearer image of the subsurface individual stratigraphic units. The 2D contour maps for Lower Permian aged Warcha Sandstone, Middle Triassic aged Tredian Formation and Early Jurrasic aged Datta Formation have been prepared using gridded TWT of the seismic profiles. The time and depth contour maps of the Datta Formation and Tredian Formation show a four way clouser oriented in the southeast dierction. The area of the closure was computed which is 24 Sq km approximately. Furthermore, the formation tops of the five wells have been used to correlate the wells for understanding the lateral and vertical variations in the stratigraphic layers. The correlation shows that the Datta Formation’s thickness increases at the centre of the basin whereas decreases on the east and south flanks of the basin. Reasons of Wells failure were concluded on the basis of the final well report and concluded that these well failure occur due to poor quality of the data and also due to some mechanical problems. Reservoircharacterization using statistical rock physics and petrophysics coupled with core data analysis can provide further insights into the hydrocarbon exploration.