Drill Stem Research Articles

Geochemical comparison of oil-bearing fluid inclusions and produced oil from the Toro sandstone, Papua New Guinea

A detailed study was carried out to compare the geochemistry of the crude oil in the Lower Cretaceous Toro sandstone reservoir in the Iagifu-7X well with oil trapped in fluid inclusions in this sandstone in the Iagifu-7X and P'nyang-2X wells in the Papuan Fold Belt. The drill stem test (DST) oils and the oils trapped in fluid inclusions show different source- and maturity-dependent geochemical parameters. Biomarkers suggest that the DST oils at Iagifu-7X were derived from clay-rich, mixed marine/terrestrial source rocks deposited under oxic conditions, probably Middle to Late Jurassic mudstones. The fluid inclusion oils were derived from a less terrestrially-influenced marine source rock deposited under less oxic conditions. The fluid inclusion oils contain 1,2,7-trimethylnaphthalene and oleanane biomarkers indicative of angiosperm input and a Cretaceous or younger source rock. These oils are more mature (calculated reflectance [ R c] = 1.02%) than the reservoired oil at Iagifu-7X ( R c = 0.84%) and condensate at P'nyang-2X ( R c = 0.84%). Source and thermal maturity parameters for all three fluid inclusion samples are similar, suggesting that they were derived from similar source rock facies. Furthermore, samples with predominantly blue vs. white fluorescing oil inclusions have no discernible geochemical maturity difference, suggesting that the use of fluorescence colours as a qualitative guide to the maturity of the trapped oil is not valid in this case. Fluid inclusion oils were trapped prior to charge of the reservoir with oil at the Iagifu-7X and gas condensate at the P'nyang-2X wells. The fluid inclusion oils therefore represent an early oil charge from a deeply buried, probably Cretaceous source rock, which started migrating into the Toro sandstone during the Miocene. At Iagifu this early oil was probably diluted by a larger volume of Jurassic oil generated at the end of the Miocene. The absence of fluid inclusions with compositions like the currently reservoired oil is interpreted to be due to oil charging an already oil-saturated zone, when diagenesis is likely to have been inhibited. At the P'nyang well, the transition from oil (as represented by the oil inclusions) to gas condensate was most likely caused by gas displacement.

Abstract: Subsurface Integration of Drill Stem Test Information in the Rocky Mountain Region Provides Low Cost Analysis of Regional Reservoir Parameters 

Abstract: Subsurface Integration of Drill Stem Test Information in the Rocky Mountain Region Provides Low Cost Analysis of Regional Reservoir Parameters 

Data Model for Drilling Information and its Application

As computing technology has evolved, so have the demands placed by the user community on the functions it provides. The expectations of software used in drilling operations are changing from a convenient way of producing the daily drilling report, to acquiring drilling data for use in engineering analysis programs. This data is expected to provide insight into an increasing array of complicated engineering operations questions. There are a number of commercial morning reporting systems in use throughout the industry. However, after collecting many years worth of drilling data, the engineer is finding that their morning reporting system cannot easily provide the answers to some very basic questions. Many providers of drilling information systems have built their applications founded on daily wellsite operations, using the latest Graphical User Interfaces (GUIs) to ensure their case of use. The data model is usually an afterthought, and is generally time rather than activity based. In some cases, the data model is used as a tool to further the system`s {open_quotes}user-friendliness{close_quotes}. This robs the application of its versatility in performing even some of the most fundamental analysis of the data. To date, neither POSC (Petrotechnical Open Systems Corporation) nor the PPDM (Public Petroleum Data Model)more » have initiated studies to develop a drilling data model. The authors will present a data model that was used as a basis for Shell Canada`s (SCan) Drilling Information System. The provision of a sound data model, that accurately reflects the fundamental data used by drilling (or other operations), is paramount to the success of any information system. Without it, the utilization of engineering operations analysis tools for optimization would be extremely difficult.« less

Thrusting and debris entrainment in a surging glacier: Bakaninbreen, Svalbard

Bakaninbreen, a 17 km long glacier terminating in fjord waters in central Spitsbergen (77°45′ N, 17°20′E), began to surge between the springs of 1985 and 1986. By summer 1994 the surge front had reached a position 3 km from the terminus and had almost ceased propagation. Structural investigations were undertaken to characterise the tectonic evolution of this thermally complex surge-type glacier, and the role played by thrusting and its effect on debris entrainment. Much of the glacier surface, particularly within and below the surge front, displayed transverse high-angle thrusts, defined by discrete fractures bounded by coarse clear ice. Some fractures were associated with a film of mud, whereas in others a discrete laver of diamicton, with interstitial ice several decimetres thick, was evident. Within the surge front, and genetically related to the thrusts, was a number of shear zones several metres wide. These were defined by fine-grained ice that was the product of the grinding up of crystals during shear (mylonitization). Three main sedimentary facies are associated with the thrusts: mud, gravelly mud and clast-rich muddy diamicton. The diamicton has the character of basal glacial debris: grain-size distribution ranging from clay to cobble size, clasts with a predominance in the sub-angular and sub-rounded classes, and striated and faceted clasts. Hot-water drilling through the glacier revealed several englacial layers above the surge front, and debris brought up on the drill stem suggests a basal origin. At least some of these englacial layers are probably the sub-surface continuations of the thrusts. The observed facies indicate that the glacier is moving over a soft, deformable bed and that thrusting is an important process in transferring debris to the surface, especially when the surge front is propagating down-glacier.

Relationship Between In-Situ Stress and Fractures and Faults in the Monterey Formation, Santa Maria Basin, California: ABSTRACT

Borehole televiewer (BHTV) data from four wells within the on- and offshore Santa Maria Basin were utilized to investigate the relationship between fracture distribution, orientation, and variation with depth and in situ stress. Analysis of stress-induced wellbore breakouts in each well shows a uniform NE-SW maximum horizontal stress (S[sub Hmax]) orientation with depth. This is consistent with the regional S[sub Hmax] direction throughout the entire seismogenic part of the crust as determined from other wellbore breakout data, NW-SE trends of active fold axes and results of kinematic stress-inversion of earthquake focal plane mechanisms. In marked contrast to the uniform stress field, analysis of fractures indicates that their orientation, dip, and frequency vary considerably within each well and laterally among them. With depth, fractures can be generally divided into distinct subsets on the basis of fracture frequency and predominant strike and dip directions. These subsets correlate with changes of lithology and physical properties indicating that factors such as tectonic history, diagenesis and structural variations may have strongly influenced the initiation and propagation of fractures. Only in the onshore well do steeply-dipping fractures strike parallel to S[sub Hmax] and are interpreted as Mode I extension fractures. In the three offshore wells, themore » fracture strike is mainly oblique or orthogonal to S[sub Hmax] suggesting that they may be distributed strike-slip or reverse faults. We believe currently active faults in the NE-SW transpressional deformation regime play a crucial role for fluid migration by providing permeability enhanced flow paths. Drill stem tests conducted in two of the offshore wells indicate that formation permeability is greatly enhanced in sections of the well where fractures strike predominantly perpendicular to S[sub Hmax] and dip at moderate to steep angles.« less

Thrusting and debris entrainment in a surging glacier: Bakaninbreen, Svalbard

Bakaninbreen, a 17 km long glacier terminating in fjord waters in central Spitsbergen (77°45′ N, 17°20′E), began to surge between the springs of 1985 and 1986. By summer 1994 the surge front had reached a position 3 km from the terminus and had almost ceased propagation. Structural investigations were undertaken to characterise the tectonic evolution of this thermally complex surge-type glacier, and the role played by thrusting and its effect on debris entrainment. Much of the glacier surface, particularly within and below the surge front, displayed transverse high-angle thrusts, defined by discrete fractures bounded by coarse clear ice. Some fractures were associated with a film of mud, whereas in others a discrete laver of diamicton, with interstitial ice several decimetres thick, was evident. Within the surge front, and genetically related to the thrusts, was a number of shear zones several metres wide. These were defined by fine-grained ice that was the product of the grinding up of crystals during shear (mylonitization). Three main sedimentary facies are associated with the thrusts: mud, gravelly mud and clast-rich muddy diamicton. The diamicton has the character of basal glacial debris: grain-size distribution ranging from clay to cobble size, clasts with a predominance in the sub-angular and sub-rounded classes, and striated and faceted clasts. Hot-water drilling through the glacier revealed several englacial layers above the surge front, and debris brought up on the drill stem suggests a basal origin. At least some of these englacial layers are probably the sub-surface continuations of the thrusts. The observed facies indicate that the glacier is moving over a soft, deformable bed and that thrusting is an important process in transferring debris to the surface, especially when the surge front is propagating down-glacier.

RESERVOIR CHARACTERISATION OF A LOW RESISTIVITY GAS FIELD-OTWAY BASIN, SOUTH AUSTRALIA

The Katnook, Haselgrove and Ladbroke Grove Fields of southeastern SA are characterised by a lack of resistivity contrast above and below known gas-water contacts, poor hole conditions, complex mineralogy and fresh formation water. A multi-disciplinary review of all available data to characterise the Pretty Hill Sandstone reservoir by integrating core, log and engineering data has enabled a comprehensive picture of reservoir heterogeneity and its influence on log response and well performance to be determined. The availability of extensive core throughout the 6 wells has resulted in the accurate modelling of reservoir porosity and the derivation of a facies-dependent, quantitative permeability log which closely matches drill stem test and production test derived permeability thickness (kh). Previous water saturation assumptions have been shown to be optimistic with Leverett J Function water saturation averaging 50-60 per cent through the reservoir. Detailed facies modelling from the cores extrapolated into areas with no core control has led to the derivation of a geological model which, when integrated into a 3D simulation, has resulted in calculated pressures within 1 per cent of those measured and has enabled the prediction of the pressure response from highly compartmentalised portions of the reservoir. Simulation-derived, material balance and volumetric original-gas-iti-place for the Katnook Field now agree to within 5 per cent.The study has resulted in changes to previously accepted evaluation procedures for wells targeting the Pretty Hill Sandstone.

Reservoir Performance of Late Eocene Incised Valley Fills, Cusiana Field, Llanos Foothills, Eastern Colombia.: ABSTRACT

The Cusiana Field is located in the Llanos Foothills of Eastern Colombia. The principal reservoir is the late Eocene Mirador Formation which comprises >50% of reserves. Currently the Mirador reservoir is providing nearly all of the 150,00bopd of production from the Cusiana Field. The Mirador reservoir comprises a stack of incised valley deposits. The fills of the valleys are dominated by quartz arenite sandstones. The average porosity of the valley sandstones is 8% which reflects abundant quartz cement ({approximately}14%) and significant compaction during deep burial ({approximately}20,000feet). Single valleys are up to 70 feet thick and exhibit a distinctive bipartite fill that reflects changing energy conditions during filling. Bases of valleys have the coarsest grain size and have sedimentological and trace fossil evidence for deposition in highly stressed, brackish water environments. The upper parts of the valleys are typically finer grained and were deposited in more saline settings. Despite the low porosity of the Mirador valleys, drill stem tests and production log data show that they have phenomenal performance characteristics. Rates of {ge}10,000bopd are achieved from single valleys. Bases of the valley fills are the key contributors to flow. Integration of detailed core and pore system analysis with the reservoir performancemore » data shows that the permeability fabric of the Mirador can be explained by original depositional architecture and simple loss of primary porosity. Comparison of Cusiana with other quartz-rich sandstones from around the world suggests that it`s low porosity/high performance is predictable.« less

北海道勇払地域におけるフラクチャー解析

This paper discusses the methodology for fracture detection and fracture porosity evaluation through core description, mud log and well logs, using data from Yufutsu gas field, Hokkaido, Japan. The youngest fracture group observed on core (System C) consists mainly of open fractures and roughly correlates with the conductive type fracture image on FMI. The remaining core fracture groups (System A and B) are filled by minerals and correlate with the resistive type fracture image. These results suggest that a substantial part of fracture pore space is associated with System C. The drill stem test results show that the most reliable fracture indications on mud log and conventional well logs are lost circulation while drilling, spiky peak of showing and abnormaly low values of RLLD. The values of φFMI and φRLLD-RLLS are low and nearly equal because both are probably close to the minimum fracture porosity. The trend of SPI (φD-φS) is similar to those of φFMI and φRLLD-RLLS, but the values of the former are several times larger than those of the latter. As above mentioned, the value of fracture porosity is various due to the difference of estimation formula and quantitative fracture porosity evaluation of the study area is still on the trial and error stage. So, further study will be needed for establishing more reliable method of fracture porosity evaluation.

The ratios of dibenzothiophene to phenanthrene and pristane to phytane as indicators of depositional environment and lithology of petroleum source rocks

The ratio of dibenzothiophene to phenanthrene and the ratio of pristane to phytane, when coupled together, provide a novel and convenient way to infer crude oil source rock depositional environments and lithologies. Such knowledge can significantly assist in identifying the source formation(s) in a basin thereby providing valuable guidance for further exploration. The ability to infer this information from analysis of a crude oil is especially valuable as frequently the earliest samples in a new area may be shows and/or drill stem test samples from exploratory wells which are characteristically drilled on structural highs stratigraphically remote from the source formation(s).A cross-plot of dibenzothiophene/phenanthrene versus the pristane/phytane ratios measured on seventy-five crude oils from forty-one known source rocks ranging in age from Ordovician to Miocene consistently classified the oils into the following environment/ lithology groups: marine carbonate; marine carbonate/ mixed and lacustrine sulfate-rich; lacustrine sulfate-poor; marine and lacustrine shale; and fluvial/deltaic carbonaceous shale and coal. The dibenzothiophene/phenanthrene ratio alone is an excellent indicator of source rock lithology with carbonates having ratios > 1 and shales having ratios < 1.The dibenzothiophene to phenanthrene and the pristane to phytane ratios can also be used to classify source rock paleodepositional environments. The classification scheme is based on the premise that these ratios reflect the different Eh-pH regimes resulting from the significant microbiological and chemical processes occurring during deposition and early diagenesis of sediments. The dibenzothiophene/phenanthrene ratio assesses the availability of reduced sulfur for incorporation into organic matter and the pristane/phytane ratio assesses the redox conditions within the depositional environment. Interpretation of these ratios has been aided by quantitative biomarker analysis and by carbon isotope data for pristane and phytane obtained by gas chromatography-isotope ratio mass spectrometry.

PETROLEUM EXPLORATION IN THE PROTEROZOIC BEETALOO SUB-BASIN, NORTHERN TERRITORY

Exploration over Roper Group outcrop in the McArthur Basin prompted Pacific Oil &amp; Gas to investigate the petroleum potential of the Beetaloo Sub-basin, a 15 000 km2 Proterozoic depression concealed beneath Phanerozoic cover. Since 1989 drilling and seismic has identified a broadly flat-lying sequence with uplifted, eroded margins. A 3 500 m composite Proterozoic section consisting of three sandstone-to-mudstone sequences has been drilled. The lower two sequences comprise conformable units of the Mesoproterozoic upper Roper Group and unconformably overlying them is a previously unknown sequence comprising the informally labelled 'Jamison Sandstone' and 'Hayfield Mudstone', probably of Neoproterozoic age.Organic-rich intervals in the Roper Group mudstones range one to three per cent TOC in the Kyalla Member, and two to seven per cent TOC in the 'Middle' Velkerri Formation. Across most of the sub-basin the oil window lies within the Kyalla Member around 900–1350 m, while the 'Middle' Velkerri Formation is around 2 500 m and well into overmaturity, but may still have potential for gas. Potential reservoirs in the Bessie Creek, Moroak and 'Jamison' Sandstones, and in sandy units within the mudstones, are compromised by diagenesis, but porosities of up to 20 per cent and permeabilities of tens and rarely hundreds of millidarcies have been measured. Encouraging shows were observed in many of these intervals, and small quantities of oil and gas have been recovered in drill stem tests. With only a few targets drilled to date, this frontier area requires more exploration before its hydrocarbon potential can be adequately assessed.

Multi-layered radial flow model interpretation of drill stem test data : Yu, Y H; Lloyd, J W J HydrolV136, N1/4, Aug 1992, P73–86

Multi-layered radial flow model interpretation of drill stem test data : Yu, Y H; Lloyd, J W J HydrolV136, N1/4, Aug 1992, P73–86

Characteristics of the bed of the Lower Columbia Glacier, Alaska

An unplanned, but unique, experiment has given an in situ measurement of the strength of deforming subglacial till under the central region of a major valley glacier. We report on both planned and unplanned borehole investigations of the subglacial shear zone of Columbia Glacier, southeast Alaska. Basal samples, coring and down‐hole water samples show that the fiord‐filling lower reach of the glacier is underlain by a thin, ∼ 7‐cm, veneer of rock debris. Fluidized debris intruded at least a meter up the borehole. At a higher site, 13 km from the terminus and above the fiord, probing, samples, and the bending of a drill stem, which was stuck in the basal zone for 5 days, showed that the basal till layer was ∼ 65 cm thick. Horizontal velocity of the till decreased monotonically downward from the ice/till interface. Till at the interface moved with the ice velocity. Plastic deformation of the drill stem gave an estimate of the strength of the basal till, which is normally described as a viscoplastic material. If the till is assumed to be either perfectly plastic or Newtonian viscous, then the strengths are as follows; the plastic yield strength of the till was 5.5×103 Pa (0.055 bar) with an upper bound of 1.3 ×104Pa (0.13 bar), while the nominal viscosity was of the order of 2×108 Pa s (2×109 poise), with an upper bound of 5×108Pa s. In neither case is the till “strength” enough to supply the bulk basal shear stress to resist the glacier flow.

Vacuum testing of the permeability of the excavation damaged zone

The vacuum permeability method provides a new approach to assessment of permeability in the near-field of rock excavations. The method, which resembles leak testing of vacuum lines, is based on the measurement and interpretation of the pneumatic response to evacuation of a rock mass. As the induced drainage area is in order of meters, the method is particularly suitable on the scale of the excavation damaged zone. The data can be evaluated either analytically or numerically. The evaluation is similar to the approach used in the analysis of drill stem tests in gas wells. Experiments on large scale laboratory models corroborated the validity of the method and the evaluation procedure. Field tests were conducted at a wide range of geomechanical conditions. The collected data indicate that there are three characteristic types of permeability distribution in the excavation damaged zone.

The Embla Field

The Embla Field is the first development of a pre-Jurassic reservoir in the Norwegian sector of the Central Graben. The field is located 5 km south of the Eldfisk Alpha platform, near the Greater Ekofisk production complex, which provides an infrastructure where development of marginal fields becomes commercially viable. Although the field was initially discovered in 1974 with the 2/7-09 well, inconclusive drill stem test (DST) and geological data left the field potential uncertain. In 1988 a second well, 2/7-20, successfully tested oil and gas from a thick sandstone of indeterminate age. A third well, 2/7-21S, drilled in 1989, gave even better test results from two separate sandstones. Core, log and DST data from these two wells indicate that the reservoir is a faulted and highly fractured sequence of conglomeratic and finer-grained sandstones deposited in a continental environment of probable Paleozoic age. A 3D seismic programme in 1989 also demonstrated the structural complexity of the field. Situated as it is on the Grensen Nose and bounded on its eastern flank by the Skrubbe Fault/Lindesnes Ridge inversion, it was evident the reservoir had experienced a complex burial and tectonic history. Poor seismic definition of the pre-Cretaceous stratigraphy further dictated the need for a flexible approach to field development. A phased development programme was initiated, justified by the reserves attributable to the 2/7-20 and 2/7-21S wells. Expendable delineation wells were avoided. Instead, deviated step-out drilling from a central template was favoured, with the intent to subsequently tie the wells back to a remotely controlled surface production facility. First production is scheduled for early 1993.

A multi-layered radial flow model interpretation of drill stem test data

Five sets of drill stem test data from adjacent zones in a borehole are analysed for hydraulic conductivities using the traditional Horner method, a single-layer radial flow model and a multi-layer radial flow model. An optimised interpretation has been used in the last model. The results show that head responses resulting from tests are important in zones juxtaposed to the test zone and must be accounted for in hydraulic conductivity determinations. The most suitable method is shown to be the optimised multi-layer radial model.

Nature and geochemistry of high molecular weight hydrocarbons (above C 40) in oils and solid bitumens

Series of hydrocarbons ranging up to C 75 have been detected by high temperature gas chromatography (HTGC) in a number of geochemical samples, including oils and waxes precipitated in drill stem pipes. A saturated hydrocarbon fraction isolated from a fossil bitumen, ozocerite, and enriched in branched/cyclic compounds, was analysed by direct insertion probe mass spectrometry (DIP/MS) and showed the presence of cyclic structures in the high molecular weight region (>C 40). The asphaltene fractions isolated from the various samples were analysed by flash pyrolysis-high temperature gas chromatography (Py-HTGC). Similar distributions of high molecular weight hydrocarbons were produced from the asphaltenes of both the oils and waxes. In vitro simulation experiments of the asphaltene fractions produced a similar distribution of high molecular weight hydrocarbons as observed from Py-HTGC, suggesting that thermal breakdown of asphaltenes may be responsible for the production, or release, of some naturally occuring high molecular weight hydrocarbons.

Geochemical constraints on formation fluid ages, hydrothermal heat flux, and crustal mass transport mechanisms at Cajon Pass

He, Ne, and helium isotopic measurements have been made on borehole fluids collected during drill stem tests at the Cajon Pass scientific drill hole. These fluids represent a dominant component (greater than 90%) of the formation fluids as determined from fluoroscein tracer measurements. The results indicate a crustally derived radiogenic helium source with excess He concentrations up to 100x air‐saturated water conditions. The gas content and the chemical composition of the borehole waters reflect a variation in the formation waters entering the hole from several discrete, identified, and poorly interconnected fracture systems. These conditions indicate a local source for the excess 4He which allows 4He model ages of 33,000 to 5×106 years to be placed on the formation fluids at this depth. This constraint suggests an upper limit of &lt;7% of the total heat flow can be removed by hydrothermal processes. These data thus provide geochemical support for a low stress fault. These model ages further indicate an effective vertical component of the fluid transport velocity of the order of 0.04–6 cm yr−1. Pressure head and in situ permeability measurements indicate flow velocities of 10−5 cm yr−1. To satisfy both of these extant conditions, fluid exchange must have occurred (as least once) in the last ∼33,000 to 5×106 years under flow conditions considerably faster than presently operable. Fluid flow in this region is therefore discontinuous with long periods of slow flow interrupted by periods of very rapid transport. Such a conclusion is consistent with both local and general observations of metamorphic geology and suggests a deep crustal fluid transport mechanism that is mechanically and/or tectonically controlled.

The technology for wireline re‐entry of deep ocean boreholes employed for the Dianaut Program

More than 850 holes have been drilled in the world's oceans over the past 24 years, in connection with the Deep Sea Drilling Project (DSDP) and the Ocean Drilling Program (ODP). At least 45 of these holes were fitted with a re‐entry cone and many were cased through the sedimentary and unconsolidated layers, allowing hole re‐entry with a drill string from a drilling vessel and wireline logging to the drill stem. Re‐entry of seafloor drill holes with a wireline logger positioned on the seabed was first successfully accomplished during the FARE program. The DIANAUT program was a scientific application of seafloor wireline re‐entry utilizing the logging shuttle ‘Nadia’ in combination with the manned submersible ‘Nautile’. The Nadia re‐entry logging system was successfully seated in drill re‐entry cones of three boreholes in the Atlantic Ocean (water depths of 1666, 4485, and, 4976 m) and logging operations with different probes (temperature, heat‐pulse flowmeter, BHTV, fluid sampler, magnetometer) were performed from the seafloor with full logging control and data acquisition from the Nautile. In the near future the logging shuttle ‘Nadia’ could be developed into a support facility for long‐term downhole measurements and later into an unmanned seafloor logging system.

Air drilling has some pluses for horizontal wells : Carden, R S Oil Gas JV89, N14, 8 April 1991, P76–78

Drilling horizontal wells with air as the circulating medium is not a common practice; however, air has come distinct advantages over drilling mud. They are: Significant increase in rate of penetration which leads to shorter drilling time. Elimination of lost circulation problems, especially in areas of very low bottom hole pressures. Continual drill stem test of potential producing formations. Minimal damage to the formation. Unfortunately, there are some disadvantages to drilling with air. Downhole motor life is shorter and less predictable. No measurement-while-drilling (MWD) system is currently available that will work consistently in air drilling environments. Hole cleaning is a problem at inclinations above 50{degree}. The horizontal section length is reduced because of the increased friction (drag) between the drillstring and borehole. The types of lithologies and targets are limited. Several horizontal wells have been successfully drilled with air or foam since 1986. At a minimum, operators drill the horizontal section with air or foam to eliminate lost circulation problems in low pressure or partially depleted reservoirs and to reduce formation damage due to drilling fluid invasion. However, problems have been encountered in drilling horizontal wells with air. Not all of the problems are unique to air drilling, but somemore » may be exaggerated by the conditions in an air-drilled hole.« less