Drill Stem Research Articles

A new borehole temperature adjustment in the Jeffara Basin (southeast Tunisia): Inferred source rock maturation and hydrocarbon generation via one-dimensional modeling

In Tunisia, most borehole temperatures used to constrain the thermal histories of sedimentary basins were previously corrected using various methods, set to best-fit domains other than the Tunisian basins. This study aimed to propose a new method of borehole temperature correction suitable for the Jeffara Basin, southeastern Tunisia. A total of 92 temperature values including bottomhole temperatures (BHTs) and drill stem test (DST) temperatures were collected from 11 boreholes in the area. The correction method consists of plotting BHT versus DST. The derived equation generates corrected temperatures close to formation temperatures. An error temperature curve following the equation was calculated (x = depth in meters and y = temperature error in °C). The error varies from to ( to ) at depths below −274 m (−898 ft). A temperature error () is proposed according to depth, and to the time elapsed since mud circulation ceased intervals. To test the method consistency, the Silurian Tannezuft hot shales Formation thermal history is simulated using the BasinMod 1-D™ software program. Two runs were tested based on the new method: (1) noncorrected BHT and (2) corrected BHT. The first run indicates that the Silurian source rock is at an early stage of the oil window. The second run shows that the source rock is mature and even at a late mature stage toward the north. Oil expulsion has occurred even at an oil saturation expulsion threshold of 5%. The results explain gas condensate production in the study area.

Analysis of drill head designs for dual-reciprocating drilling technique in planetary regoliths

The dual-reciprocating drill (DRD) is a biologically-inspired concept which has shown promise in planetary environments, requiring a lower overhead force than traditional rotary drilling techniques. By using two reciprocating backwards-facing teethed halves to grip the surrounding substrate, it generates a traction force that reduces the required overhead penetration force. Research into DRD has focused on the effects of operational and substrate parameters on performance compared to static penetration, with minimal study of the geometrical parameters which define the drill head. This paper presents the exploration of the effects of drill head design on drilling depth and power consumption. Sixteen variations of the original design were tested in planetary regolith simulants up to depths of 800mm. The experiments showed relationships between final depth, total drill radius and cone shape, though the teeth design had a negligible effect on performance. These results can be used alongside the previous research to optimise the future design and operation of the DRD. Drill stem bending was seen to cause an increase in drilling speed and depth, leading to the exploration of the mechanics of diagonal drilling. This resulted in the proposal of a fully-integrated system prototype that incorporates both reciprocating and lateral motion mechanisms.

Sea Lion Field discovery and appraisal: a turning point for the North Falkland Basin

In 1998, the first six wells were drilled in the North Falkland Basin, and demonstrated the presence of excellent source rock and good reservoirs. Oil and gas shows were encountered in all but one well; however, no commercial volumes of hydrocarbons were proven. At that time, the focus of exploration was almost exclusively on traditional structural traps mapped on two-dimensional (2D) seismic surveys. Eleven years later, in May 2010, Rockhopper Exploration discovered the Sea Lion Field, which has over a billion barrels of estimated oil in place. Discovery well 14/10-2 was drilled on three-dimensional (3D) seismic data acquired by Rockhopper in 2007. Unlike the targets of the first campaign, the Sea Lion prospect was a stratigraphic trap imaged as a series of fan-shaped amplitude anomalies. Following a successful drill stem test of the SL10 and SL20 fans in the discovery well, Rockhopper embarked on an aggressive field appraisal and exploration drilling programme in the Sea Lion area. A second fully engineered production test was successfully performed on a later well to establish commercial flow rates. In addition to appraising the Sea Lion reservoirs, a further three hydrocarbon-bearing reservoirs were proven (Casper, Casper South and Beverley). Comprehensive data acquisition and analysis has been key to de-risking the first commercial development in the basin. A full suite of wireline logs was run in all the appraisal wells; seven wells were extensively cored and fluid samples were recovered for analysis from all reservoirs. In parallel with the drilling campaign, in 2010–11 a total of 4500 km 2 of 3D seismic data was acquired and processed in a collaborative programme with Argos and Desire. In 2012, Premier Oil farmed-in to the licence and assumed operatorship with 60% equity. Dynamic modelling indicates that estimated resources of approximately 160 million barrels (160 mmbbl) can be recovered from the north-east flank of the field based on a Floating Production, Storage and Offloading (FPSO) facilities concept for Phase 1 of the field development. The concepts for additional phases of field development are currently being evaluated.

Calculation of water saturation in low resistivity gas reservoirs and pay-zones of the Cretaceous Grudja Formation, onshore Mozambique basin

The water saturation of a hydrocarbon bearing formation is usually calculated via the conductivity of the formation water, as defined by Archie, 1942. However, in some formations such conventionally calculated water saturation contradicts values calculated from the Nuclear Magnetic Resonance (NMR) tool and from the Drill Stem Test (DST). Here we discuss such a case of low resistivity pay zones in the J- and K-Reservoirs, of the Lower Grudja Formation of Maastrichtian age, onshore Mozambique basin, in which conventional log analysis contradicts water saturation calculated from the NMR and by the Drill Stem Test.For both, the J-Reservoir and K-Reservoir, the water saturation (Sw) was calculated using the Archie equation and the Simandoux equation, that accounts for clay bound water but not for silt, and the results were compared to NMR-calculated water saturation. A new algorithm that improves the accuracy of water saturation calculation was introduced. This new algorithm takes into account the clay- and silt-bound water within the overall reservoir resistivity. It is demonstrated that the clay- and silt-bound water must be included in water saturation calculations, where the formations are rich in silt and clay. The Simandoux equation and the new algorithm yield significant improvement in water saturation results for the J- and K-Reservoirs, when compared to water saturation calculated using the Archie's equation.

The use of kernel principal component analysis and discrete wavelet transform to determine the gas and oil interface

The variations of pore fluid energy encoded within resistivity well logs can be considered as a significant attribute in the determination of reservoir fluid contacts. As a paramount technique in isolation and manipulation of certain patterns hidden in masses of data, wavelet analysis can effectively unveil this attribute. In this study, the discrete wavelet transform was employed on new well logs generated by kernel principal component analysis to monitor the pore fluid energy of pay zones at two previously appraised wells. An expert wavelet-based model was extracted by revealing the latent pattern of pore fluid energy variations. This model was then used to specify the gas and oil interface in a target well contiguous with the appraised wells. The gas and oil interface obtained from the expert wavelet-based model was confirmed by the drill stem test analysis. Results of this investigation suggest that monitoring pore fluid energy with such a method can be considered a highly functional attribute in determining the gas and oil interface.

Analysis of Thermal Recovery Horizontal Well Drilling Technology in Gudong Nine District

The thickness of oil reservoir in Gudong nine district is normally 2 to 8 m. The upper parts of this reservoir are fluvial facies. Also, the sand body is a positive rhythm combination, which includes fine sandstones, coarse sandstones, argillaceous siltstones and mudstones from top to bottom. The mine type of oil wells in this area is the thermal recovery horizontal well, which is normally featured in shallow, weak formation (easily to collapse) and unmanageable wellbore trajectory. Considering drill bits, drill stem structure and drilling parameters, the horizontal well drilling technology combines the horizontal well completion technique and MEG drilling fluid system. It has been proved that this technology is especially good at increasing drilling speed and efficiency. Key words: Horizontal well drilling technology; Weak formation; Wellbore trajectory; MEG drilling fluid; Well completion technique

Tight Gas Sandstone Reservoirs Evaluation from Nuclear Magnetic Resonance (NMR) Logs: Case Studies

Tight gas sandstone reservoirs parameters, such as porosity, permeability and initial water saturation, are difficult to be precisely estimated from conventional logs. What’s more, the effective gas-bearing formations cannot be directly identified either due to the characteristics of complicated pore structure, strong heterogeneity and high irreducible water saturation. Nuclear magnetic resonance (NMR) logs, which are usually used to evaluate reservoir pore structure, are found to be effective in evaluating tight gas sandstone reservoirs. In this study, typical tight gas sandstone reservoirs of southwest China are used as examples; techniques of estimating porosity, permeability, initial water saturation and constructing pseudo-capillary pressure curve to quantitative evaluate tight sandstone reservoirs pore structure are studied. The acoustic and NMR logs are combined to calculate porosity. The technique proposed by Volokitin et al. (1999) is used to construct pseudo-capillary pressure curves from NMR logs. The saturation-height-function method is used to estimate initial water saturation, and the Swanson parameter based model is established to calculate permeability from constructed pseudo-capillary pressure curves. Comparisons of estimating porosity, permeability and water saturation with core-derived results illustrate that these techniques are effective in tight gas sands evaluation. Finally, the effective tight gas sands can be identified through combined use of the estimated reservoir parameters and constructed pseudo-capillary pressure curves from NMR logs, which is verified by the drill stem test data.

Dictionary of petroleum exploration, drilling & production

Contents: Drilling & completion records Rotary drilling rig Cable tool drilling rig Crank counterbalanced bean pumping unit Geological time scale Giant oil & gas fields Mineral properties Sandstone limestone classifications Carbonate porosity Common geological map & log symbols Drill stem test symbols Flow sheet symbols Land subdivisions (U.S.) Geological features (U.S. & Canada) Unit conversion factors Atomic weights & numbers Greek alphabet.

Sand production assessment considering the reservoir geomechanics and water breakthrough

Sand production assessment is essential from the early stages of field development planning for completion design and later for the production optimisation. Unconsolidated and weakly consolidated sandstones are prone to fail at a low flowing bottomhole pressure during hydrocarbon production. To predict the critical flowing bottomhole pressure or a safe drawdown, a geomechanical model that integrates in situ stresses, rock mechanical properties, the well trajectory, reservoir pressure, the production plan and the depletion trend is required. For a given stress field, well trajectory and production plan, the rock strength index is a key parameter that has significant impacts on the sanding risk. This paper presents the results of a study investigating the potential of sand production from primary and secondary target reservoir rocks in a petroleum field in offshore Vietnam. A poroelastic analytical approach was used to investigate if sands will be produced from the open holes or perforations. The criterion of sanding was formulated to be the effective maximum principal stress to be greater than the effective rock strength. Observations of sanding or no sanding during drill stem tests (DSTs) were used to calibrate the sanding model to be used for sanding predictions of future production wells. The effects of reservoir pressure depletion on sanding risks were investigated using the stress arching theory. Since the water production from target reservoirs was observed in the nearby fields, the analysis was performed to investigate the effects of water production on rock weakening that may cause higher risks of sanding. The results showed low risks of sanding for majority of the reservoirs, with drawdowns as high as 3,000 psi at the original reservoir pressure. The drawdown was, however, required to reduce to 500 psi to produce sand-free after depleting the reservoir by more than 90% of its original pressure. The results of this study led to the decision of completing the wells without using sand control equipment and to avoid sanding by controlling drawdown for the life of the well.

Reservoir geology of the Paleocene Forties Sandstone Member in the Fram discovery, UK Central North Sea

Abstract The Fram discovery, located in the UK Central North Sea, comprises the Paleocene-aged Forties Sandstone Member with an oil rim and primary gas-cap trapped within a four-way dip closure around a pierced salt diapir. The Forties Sandstone Member reservoir at Fram is characterized by very-fine- to fine-grained sandstones interbedded with shales with post-depositional small-scale slumping and sand injection, interpreted to be the product of high-density turbidity currents and debris flows. Deposition was in an overall distal and marginal, basin-floor lobe environment. The Forties reservoir interval is considered to comprise a series of offset-stacked, turbidite lobes characterized by a systematic variation from axial amalgamated sandstone facies to more distal, marginal and thinner-bedded heterolithic sandstone facies, producing an overall sheet-like reservoir architecture. The Forties reservoir at Fram is thinner and poorer when compared with more proximal parts of the Forties submarine fan system, and reservoir quality is strongly controlled by sedimentary facies. The architecture of the reservoir is expected to result in poorer vertical, but greater lateral, stratigraphic continuity when compared with more channelized Forties reservoirs such as the Nelson and Forties fields further to the north. A key step in understanding and characterizing the Fram reservoir was the appraisal drilling in 2009, which included coring, comprehensive wireline logging, formation pressure data acquisition and a drill stem production test. This paper provides an overview of the Fram reservoir geology and demonstrates how integration of data acquired in the 2009 29/3c-8,8z appraisal wells with 3D seismic datasets, existing E&A wells and analogues has helped to improve reservoir characterization and identify the major subsurface uncertainties needing to be addressed during the field-development planning.

Numerical simulation of velocity profile in eccentric annulus

Annulus flow is a phenomenon which is frequently encountered in many industrial processes and has been under investigation for many decades. It is relatively simple to study concentric annulus flow. However, if the annulus is eccentric, calculations become complex due to the asymmetry of the eccentric annulus flow. During drilling operation, the space between the drill stem and the well wall is generally an eccentric annulus. Especially in highly deviated wells and horizontal wells, the drill stem will be located at the low side of the wellbore because of gravitational effects, thus, a fully eccentric annulus is formed. The velocity profile in the eccentric annulus will exert a great impact on the transportation and distribution of the cuttings, which is very important to prevent the drill string from being buried and avert sticking incidents. Based on a single-phase flow model and a solidliquid two phase mixture drift model, (using the computational fluid dynamics (CFD) software) we analyze the influence of six factors in this paper. These factors are the • flow rate, • fluid viscosity, • the type of fluid, • eccentricity, • annulus geometry size and • cuttings concentration. According to the results of numerical simulation, we can see that the velocity profile in the eccentric annulus is asymmetrical. There will be a high-speed basin in the wide gap of the annulus while the low-speed basin will lie in the narrow gap. With increasing flow rate, annulus geometry size and a decrease of the eccentricity, the area of the high-speed basin in the annulus will be increased and that of the low-speed basin will be decreased. This will improve the uniformity of the annulus flow. With increasing fluid viscosity and cuttings concentration, the velocity in high-speed basin of the annulus will be increased, at the same time, the velocity in low-speed basin will be decreased and the change of the velocity is not evident. However, the pressure loss in annulus will increase rapidly. Therefore, we have to ensure that the velocity at the low-speed basin is large enough to transport the cuttings and to avoid the debris deposition in the drilling operation. At the same time, the borehole pressure should be taken into consideration when we select the reasonable drilling fluid viscosity.

On the appraisal and development of ST-X field: uncertainties and challenges

This paper summarizes theuncertainties and challenges in appraising and developing the ST-X gas condensate field, which is offshore Vietnam in Block 15-1. Drill Stem Test (DST) results show that the ST-X field has moderate to low permeability, multiple flow boundaries/barriers, and at least 2 PVT regions. To understand the impact of these and other important reservoir parameters on ultimate gas and condensate recovery and well count, a reservoir simulation study was performed. The study demonstrates that there is a wide range of possible ultimate gas and condensate recoveries and well counts. The top causes for this wide range are the heterogeneity in permeability distribution and flow boundaries/barriers. In addition to the subsurface risks, drilling cost of a ST-X well is very high. The high well cost in combination with the field being offshore, having low permeability and possibly numerous reservoir compartments dramatically increase the risk of a full field development.

Multiple overpressure systems and their relationship with hydrocarbon accumulation in the Qikou Depression of the Bohai Bay Basin, China

Pressure measurements using drill stem tests and estimates from log data calculation indicate that three vertically stacked regional pressure compartments exist in the Qikou Depression of Bohai Bay Basin, N. China. The compartments comprise hydrostatic, upper weak, and lower overpressure systems. Laterally, overpressure (pressure coefficient > 1.2) occurs in the deeper areas and weakens gradually from the centre to the margin of the depression. The accumulation of oil and gas exhibits the interesting characteristics of oil‐bearing layers above gas‐bearing layers in the Qikou Depression. The pattern can be accounted for by the evolution of overpressure system, the maturity process of the source rock and the main fault activity. In the late Dongying Formation (Ed, 30 Ma), the lower overpressure system began to form shape, and the hydrocarbon sources generated a large volume of oil. However, because there was no migration pathway, the oil only accumulated in the original strata. In the late Guantao Formation (Ng, 12 Ma), the gas was generated, the upper overpressure system formed gradually, and the activity of the main fault gradually increased. Then, the overpressure pushed the early gathered oil to flow from the lower overpressure system into the upper overpressure system. Afterwards, the activity of the main fault decreased again and remains weak until now. Thus, later generated natural gas cannot keep migrating along the main fault and can only accumulate in the lower overpressure system. Copyright © 2014 John Wiley & Sons, Ltd.

Analysis of drill stem testing technology of the Malm carbonate rocks of the Carpathian Foothills, in the aspect of geological research and exploration decisions

1. InTRoDUcTIonThe credibility of drill stem tests results performed with DST tools depends largely on the technology used. The Polish Oil and Gas Company most commonly use double-cycle drill stem tests, which, in the case of inflow to DST tool oil or reservoir water, enable among others the evaluation of [1, 2]:‒ changes of permeability of reservoir rocks in closer and more distant parts of the near-wellbore area test with DST,‒ change of yield index in the first and in the second sampling cycle,‒ relieving the given horizon of reservoir rocks from the repression of the column of the drilling mud.In the case of natural gas inflow to DST and mud spacer self-acting outflow from DST column, the technology of drill stem test changes from double-cycle to multi-cycle with clas-sical open flow operation. Thanks to open the flow operation, it is possible to remove the mud from bottom hole and declogging the near-wellbore area rocks.The Baker Inflatable type tool allows us to perform selective reservoir test, mostly in open hole sections of boreholes but also in the case of large caverns in borehole walls [1]. Then the inflow of reservoir fluid is from a predetermined interval of wellbore. This allows to shutoff the inflow of bottom water to the DST tool and reduces forming the water cone.

Origin of Formation Water from the Unayzah and Khuff Petroleum Reservoirs, Saudi Arabia

Chemical and isotopic fingerprinting techniques provide support for tracing the origin and evolution of formation waters taken during downhole and drill stem tests from exploration wells in Saudi Arabian oil and gas fields. Low molar Cl/Br ratios (85-93) and a δ18O reverse loop suggests an evaporative seawater origin for hypersaline water from the Upper Permian-Lower Triassic Khuff Formation. In contrast, formation water from the Upper Carboniferous-Lower Permian Unayzah Group shows a heterogeneous trend between low salinity/low δ18O freshwater and hypersaline/intermediate δ18O brine, the latter being a product of evaporated seawater. Unayzah water salinity increases linearly with depth at the rate of 77 to 98mg/L per meter, allowing quantitative prediction of water resistivity (Rw) at specific reservoir depths. The increase in Ca and depletion of Mg and HCO3 with Unayzah depth suggests the impact of temperature-triggered ion exchange processes that alter the primary host rock and formation water composition.

CSG well testing—Santos' experience in Queensland

Permeability of the cleat system is a key factor controlling the productivity of CSG reservoirs and, therefore, the commerciality of development projects. Well testing is routinely used to provide representative values of coal permeability. The authors’ experience has shown pressure transient behaviour in coal reservoirs to be similar to those in primary porosity systems, with pseudo radial flow frequently observed, and the dual-porosity signature largely absent. Despite the authors’ best efforts in test design, large permeability variation and extremely high skin factors have been seen. The authors have run variations of drill stem tests (DSTs), injection tests, and wireline tests to understand the dependency of results to test methods, and the validity of results obtained. Pertinent examples of each type of test are discussed. Finally, recommendations to reconcile well test results to actual well performance are presented.

Geothermal and rheological regime in the Po plain sector of Adria (Northern Italy)

We present a thermo-rheological study of the Adriatic crust in the central Po plain (Northern Italy), which records the convergence of the Alpine and Apennine external fronts. The present thermal regime of the crust is inferred from geological and geophysical data from oil exploration. A set of temperature data from 37 deep boreholes (bottom hole, drill stem, and production test temperatures) is used to estimate undisturbed formation temperatures down to 6-7 km of depth. Best quality data are used to estimate upper crustal geotherms, which are subdivided into four groups taking into considerations the following factors: i) presence/absence of relevant fluid circulation; ii) conductive thermal refraction; iii) recent sedimentation, and iv) other disturbing tectonothermal processes (e.g., recent tectonics). Assuming average corrections for temperature data affected by recent sedimentation effects, geotherms fall within the same range and provide a homogeneous thermal signal. Temperature measurements in the upper ~7 km are used to constrain a 1-D thermal model at the crustal scale. The best fitting geotherm gives a thermal gradient of ~23 ± 5 mK m-1 (over 7 km of depth), a surface heat flow of ~46 ± 9 mW m-2, and an estimated Moho temperature of 620 ± 80 °C.Using the estimated crustal structure and composition and the best-fitting geotherm, a representative strength envelope is obtained.For hydrostatic and supra-hydrostatic pore pressures, the calculated total crustal strength of this sector of the Adria microplate (not including the upper mantle contribution) is in the 1.8-2.5 TN m-1 range. Considering also the lithospheric mantle contribution, the total lithospheric strength is estimated to be between 23 (wet peridotite)and 39 (dry peridotite) TN m-1.

Application of NMR logs in tight gas reservoirs for formation evaluation: A case study of Sichuan basin in China

Permeability, irreducible water saturation and other information associated with the pore size, such as capillary pressure, are very important input parameters in tight gas reservoir evaluation. Fortunately, those parameters can be well estimated from field NMR logs, if the proper calibrations between NMR relaxation time and capillary pressure were established with measurements from core samples. In this study, a novel calibration technique, which is used for constructing capillary pressure curve from NMR logs by combining the classical SDR model with J function, is proposed and the corresponding model is established. Based on the laboratory measurements of 54 plug samples taken from the Upper Triassic sandstone formation (Xujiahe Formation) in Anlu district, Sichuan basin, Southwest China, the model parameters are calibrated. With the calibrations established and procedures proposed in this paper, the synthetic capillary pressure curves of reservoir can be constructed from field NMR spectrum. Also from those laboratory measurements, the parameter of Kϕ (defined as the pore structure index) can be well related to the Swanson's parameter derived from capillary pressure curve. This correlation could then be used for estimating reservoir permeability from the synthetic capillary pressure curve. After formation is classified into three types by using the pore structure index, the pore throat radius cutoffs can be acquired to calculate irreducible water saturation from the pore throat radius distribution. The proposed techniques and procedures are applied in field logs and the estimated information and parameters are well verified by core and drill stem testing data. By combining with the information of reservoir pore structure, permeability and irreducible water saturation, potential low resistivity contrast gas bearing reservoirs can be identified from water layers.

第1回メタンハイドレート海洋産出試験におけるフローテストシステムの概要について

In phase 1 of the Japan's Methane Hydrate Exploitation Program, the method to decrease the hydro static pressure by use of a submersible pump (the depressurization method) was recognized to be essential for the production technique. In phase 2, the basic design for the down hole production test system for offshore production tests was implemented by combining the technologies for DST (drill stem test) that are usually used in conventional oil and gas offshore production test operations. In respect of the surface production test system, the basic plan related to the necessary production facilities was designed and the specification of the floating drilling vessel suitable for the necessary facilities was also investigated. Regarding the produced water treatment system, framing of the conceptual design, organizing the regulations related to discharge, and examination of the environmental assessment have been investigated.

Quantifying the impact of oil-based mud contamination on representative condensate reservoir fluid characterisation

As hydrocarbon resources become more marginal, reducing data uncertainty associated with exploration and appraisal drilling becomes more important. For gas condensate fields where a great deal of the value is stored within the recovered liquids, variations in the condensate gas ratio (CGRs), or gas expansion factors (Bg) for example can have a considerable impact on the development strategy. Understanding the fluid in place is often key to the decision as to whether a development should go ahead or not. A considerable proportion of wells are drilled with oil-based mud. When fluid sampling is executed, the in-place reservoir fluid is often contaminated to various levels with this mud. The intention of this extended abstract is to gain an understanding of how much contamination can be accurately corrected. Several case studies are undertaken incorporating fluids from the same fields obtained in different fashions. Contaminated samples sourced from small volume probes on open-hole formations, for example an MDT or RCI tool, are compared with assumed clean samples obtained downhole during drill stem tests (DST). A suitable equation of state (EOS) is then selected and tuned to match experimentally derived results from both data sets. The small probe sample is then numerically decontaminated for mud, producing a clean EOS for comparison. By quantifying the differences in simulated depletion experiments, a judgement can then be made as to how much contamination can accurately be compensated.