Modular Formation Dynamics Tester Research Articles

Analyzing in situ stresses and wellbore stability in one of the south Iranian hydrocarbon gas reservoirs

This study aims to analyze in situ stresses and wellbore stability in one of the Iranian gas reservoirs by using well log data, including density, sonic (compressional and shear slowness), porosity, formation micro-image (FMI) logs, modular formation dynamics tester (MDT), and rock mechanical tests. The high burial depth, high pore pressure, and strike-slip stress regime of the field require an optimal design of geomechanical parameters based on an integrated data set consisting of static and dynamic data, which is available for this study. Firstly, poroelastic modulus and vertical stress were calculated. Afterward, the Eaton’s equation was used to estimate pore pressure from well logging data. The geomechanical parameters were also calibrated through the interpretation of image data, the use of the modular formation dynamics tester (MDT), and laboratory rock mechanic tests. Employing poroelastic equations, the lowest and highest horizontal stresses were calculated. It was shown that the maximum horizontal stress and minimum horizontal stress correspond to sigma H and sigma h, indicating the strike-slope fault regime. The findings of this research indicated that the equivalent mud weight (EMW) resulted in 10–13 ppg suitable for the Kangan Formation and 11–14 ppg suitable for the Dalan Formation. Additionally, the well azimuth in the NE-SW direction provided the best stability for drilling the encountered formations. Therefore, the results of this study serve as cost-effective tools in planning adjacent wells in carbonate formations of gas field to predict the wellbore stability and safe mud window.

Pore Pressure Prediction and Its Relationship with Rock Strength Parameters and Weight on Bit in Carbonate Reservoirs (A Case Study, South Pars Gas Field)

Accurate pore pressure knowledge is particularly critical in drilling, such as drilling safety (avoidance of blowouts and well control lost-time incidents). Pore pressure prediction in carbonate reservoir due to the fact that the pore system and fractures are more complex than the clastic reservoir, also the effectiveness of pore pressure on drilling parameters like weight on bit that has direct effects on drilling rate is very important. As well as, the pore pressure and rock strength parameters have a special place in geomechanical studies. In this study, pore pressure was calculated using the porosity and effective stress in the carbonate reservoir. The porosity was calculated with three methods: neutron–density, neutron–sonic and sonic. The rock strength parameters (Bulk and Shear modulus) were calculated using P and S waves obtained from dipole shear sonic imager log. The calculated pore pressure was compared with modular formation dynamics tester (MDT), WOB and rock strength parameters. The result of the study showed that among available methods, predicted pore pressure with sonic porosity has the best matched to MDT data. Moreover, pore pressure has an inverse relationship to WOB and rock strength parameters, so that with increasing pore pressure of both WOB and rock strength parameters were decreasing. The comparison among predicted pore pressure, mud weight and MDT data was showing that the predicted pore pressure has high accuracy and can use it for geomechanical studies and having a safe drilling operation.

Reservoir compartmentalization and fluid property determination using a modular dynamic tester (MDT): case study of an Algerian oil field

Compartmentalizing the reservoir and determining its initial properties are key steps in the development of an oil field. These steps are mainly performed to determine the number and types of fluids in the reservoir. They are also carried out to establish the initial reservoir pressure and reservoir potential. For each fluid zone, it is essential to identify the fluid present and its range. The oil reservoir examined in the present case study consisted of different zones with ambiguous fluid limits. Thus, the pressure gradients and variations in this reservoir were measured using a modular formation dynamics tester (MDT). This device can be employed to discriminate between formation fluids in real time. An analytical analysis of the measured pressure gradients allowed the reservoir compartments to be defined, taking into account the types of reservoir fluids present. The investigation also aimed to identify the initial reservoir conditions and establish the free water level (FWL) in each fluid zone. Thus, with similar setting, reservoir characterization and heterogeneity may constitute a key factor approach to be examined. The oilfield analyzed in this work, which is part of the Hassi Berkine basin in the Saharan platform (southeastern Algeria), has an anticlinal structure. From a sedimentological point of view, it consists of fluvial-continental deposits. Some erosional effects of the Hercynian unconformity influence the top of the Frasnian clays present. The main hydrocarbon reservoir is located in the Lower Triassic Clayey Sandstone (TAGI), the current name for the Triassic reservoir in the Sahara platform in the investigated area. The TAGI is divided into three levels: the upper TAGI (TAGI-U), middle TAGI (TAGI-M), and lower TAGI (TAGI-L). Data revealed several pressure gradients along the depth profile of each borehole section, implying significant changes in fluid properties. Substantial differences in pressure between oilfield boreholes (e.g., between the boreholes through TAGI-U+M and TAGI-L) were observed. The equivalent densities for the pressure gradients indicate that the fluid succession in the deposits is oil (TAGI-U+M), water (TAGI-M), and then oil again (TAGI-L). A stratigraphic barrier between TAGI U+M and TAGI-L was identified. By superimposing the pressure gradients observed in wells 1 and 2, two reservoir compartments were deduced. Furthermore, based on the pressure evolution with depth and the density record, two free water levels (FWL) in addition to the initial pressure were identified for the reservoir.

DISCRETE FRACTURE NETWORK (DFN) MODELLING OF FRACTURED RESERVOIR BASED ON GEOMECHANICAL RESTORATION, A CASE STUDY IN THE SOUTH OF IRAN

Fractured reservoirs have always been of interest to many researchers because of their complexities and importance in the oil industry. The purpose of the current study is to model the fractured reservoir based on geomechanical restoration. Our target is the Arab Formation reservoir which is composed of seven limestone and dolomite layers, separated by thin anhydrite evaporate rock. First of all, in addition to the intensity, the dip, and the azimuth of the fractures, the magnitude and the direction of the stresses are determined using wireline data e.g. photoelectric absorption factor (PEF), sonic density, neutron porosity, a dipole shear sonic imager (DSI), a formation micro imager (FMI), and a modular formation dynamics tester (MDT). Then, the seismic data are interpreted and the appropriate seismic attributes are selected. One of our extracted attributes was the ant tracking attribute which is used for identifying large-scale fractures. Using this data, fractures and faults can be identified in the areas away from wells in different scales. Subsequently, the initial model of the reservoir is reconstructed. After that, the stress field and the distribution of fractures are obtained using the relationship between the stresses, the strains, and the elastic properties of the existing rocks. The model is finely approved using the azimuth and the intensity of fractures in the test well. Our findings showed that the discrete fracture network (DFN) model using geomechanical restoration was positively correlated with real reservoir conditions. Also, the spatial distribution of fractures was improved in comparison to the deterministic-stochastic DFN.

A nonlinear approach for predicting pore pressure using genetic algorithm in one of the Iranian petroleum carbonate reservoirs

The fluid pressure within a formation pores is called the pore pressure in petroleum engineering. The estimation of pore pressure is a challenging task during a reservoir’s life cycle. An impermeable rock, such as shale, confides the fluids which lead to anomalously high pressures. Besides, during the exploitation life of a reservoir, the pressure reduces in the reservoir. The estimation of these high-risk pore pressures is an essential task in planning for infill drilling and field development. Herein, we propose a nonlinear model for pore pressure estimation, using a genetic algorithm. We compare our method with two of the classical linear methods for pore pressure estimation, the modified Eaton method and the Bowers method, using the Modular Formation Dynamics Tester (MDT) and well logs data related to an Iranian oil-bearing carbonate reservoirs. The results of the nonlinear estimation models showed higher accuracy and less uncertainty than the other models. The studied oil field is in the development phase; therefore, a reliable estimation of pore pressure decreases the future drillings risks and can find application in hydraulic fracturing, completion, and cement works operations.

India National Gas Hydrate Program Expedition-02: Operational and technical summary

Abstract The India National Gas Hydrate Program is being steered by the government of India's Ministry of Petroleum and Natural Gas (MoPNG) with participation of Directorate General of Hydrocarbons (DGH), Oil and Natural Gas Corporation Limited (ONGC), and the National Oil Companies and Research Institutes of India. The India National Gas Hydrate Program Expedition 01 (NGHP-01) established the presence of gas hydrate in the Krishna Godavari (KG) and Mahanadi Basins and in the offshore area of the Andaman Sea Basin. However, the gas hydrates discovered during NGHP-01 were mainly distributed as fracture-filling material in fine-grained clay-rich sediments. The India National Gas Hydrate Program Expedition 02 (NGHP-02) was carried out with an objective to discover gas hydrate in sand-rich sediment along the eastern offshore margin of India. ONGC planned and executed NGHP-02 on the behalf of the MoPNG. NGHP-02 started on March 3, 2015 and was completed on July 28, 2015 (total 147 days) using the Japanese scientific Drilling Vessel Chikyu (D/V Chikyu). During NGHP-02, 42 holes at 25 sites were drilled, cored, and/or surveyed with downhole logging tools. These sites were located in four areas along the eastern margin of India and formally named Area A (Mahanadi Basin, three sites), Area B (northern part of the KG-Basin, twelve sites), Area C (central part of the KG-Basin, six sites), and Area E (southern part to the KG-Basin, four sites). All 25 sites established during NGHP-02 were first drilled and logged with logging-while-drilling (LWD) tools and an additional 17 holes were then drilled and/or cored with conventional coring tools (HPCS/ESCS) or pressure coring tools (PCTB). Wireline logging was conducted in 10 holes and formation tests using a dual packer Modular Formation Dynamics Tester (MDT) tool were carried out in two holes. The onboard science team used the laboratory facilities on the D/V Chikyu to examine and analyse the physical properties, geochemistry, and sedimentology of all the cores collected during the expedition. Core samples were also analysed in additional post-expedition shore-based studies conducted in numerous domestic and international gas hydrate research laboratories. The NGHP-02 sediment cores were archived at the National Gas Hydrate Core Repository in Mumbai (India), which is associated with the ONGC Gas Hydrate Research and Technology Centre (GHRTC). The necessary data for characterizing the occurrence of gas hydrate, such as interstitial water chlorinities, core-derived gas chemistry, physical and sedimentological properties, thermal images of the recovered cores, pressure core and downhole measured logging data (LWD and/or conventional wireline log data), were obtained from most of the drill sites established during NGHP-02. Almost all the drill sites yielded evidence for the occurrence of gas hydrate; however, the inferred in situ concentration of gas hydrate varied substantially from site to site. For the most part, the interpretation of downhole logging data, core thermal images, interstitial water analyses, and pressure core images from the sites established during NGHP-02 indicate that the occurrence of concentrated gas hydrate is mostly associated with coarser grained (sand-rich) sediments. This paper presents the operational and technical summary of NGHP-02.

Constraints of three-dimensional geological modeling on reservoir connectivity: A case study of the Huizhou depression, Pearl River Mouth basin, South China Sea

The Z21 gas field is the only one gas field in the Huizhou depression. The distributions of sandstone and mudstone in the adjacent west zone control the extent of the Z21 gas field, making the confirmation of the reservoir connectivity between the west zone and main zone (RCWM) crucial. In this study, a practical workflow was proposed to confirm the RCWM. First, the sandstone and mudstone distributions were modeled by a sequential indicator simulation, using the vertical proportion curves as constraints. The porosity and permeability distributions were then predicted using a sequential Gaussian simulation based on sandstone and mudstone models. The sandstone, mudstone, and physical property models were treated as components of a geological embryonic model (GEM) prior to the RCWM confirmation. Different hypotheses on the RCWM of the GEMs were drawn, bringing variations to the GEMs and the GEMs turned to be different new models. These new models were then applied to numerical simulations, not only to perform quality checks, but also to attain the simulated formation pressure coefficients (Pfcs) and couple the study with the current formation pressure coefficients (Pfcc) derived from the modular formation dynamics tester (MDT). A hypothesis is negated if the Pfcs is not equal or approximately equal to the Pfcc. A coupled result was iteratively generated until the RCWM was confirmed. This coupling study on reservoir connectivity makes use of general geological reservoir models and highlights the ingenious designs based on different hypotheses of the RCWM to generate reliable results. Coupling study shows that distributions of formation pressure in the west zone of Z21 field are largely affected by a low-permeability belt and RCWM is proved weak due to the existence of the low-permeability belt.

Pore pressure prediction and modeling using well-logging data in one of the gas fields in south of Iran

Abstract Knowledge of pore pressure is essential for cost-effective, safe well planning and efficient reservoir modeling. Pore pressure prediction has an important application in proper selection of the casing points and a reliable mud weight. In addition, using cost-effective methods of pore pressure prediction, which give extensive and continuous range of data, is much affordable than direct measuring of pore pressure. The main objective of this project is to determine the pore pressure using well log data in one of the Iranian gas fields. To obtain this goal, the formation pore pressure is predicted from well logging data by applying three different methods including the Eaton, the Bowers and the compressibility methods. Our results show that the best correlation with the measured pressure data is achieved by the modified Eaton method with Eaton׳s exponent of about 0.5. Finally, in order to generate the 3D pore pressure model, well-log-based estimated pore pressures from the Eaton method is upscaled and distributed throughout the 3D structural grid using a geostatistical approach. The 3D pore pressure model shows good agreement with the well-log-based estimated pore pressure and also the measured pressure obtained from Modular formation Dynamics Tester.

Pore Pressure Prediction and Modeling Using Well-Logging Data in Bai Hassan Oil Field Northern Iraq

The Bai Hassan Field is one of the Iraq’s giant oil fields with multiple pay zones similar to most of the northern Iraq oil fields. Knowledge of pore pressure is essential for economically and save well planning and efA¯Â¬Âcient reservoir modeling. Pore pressure prediction has an important application in proper selection of the casing points and a reliable mud weight. In addition, using cost-effective methods of pore pressure prediction, which give extensive and continuous range of data, is much reasonable than direct measuring of pore pressure. The main objective of this project is to determine the pore pressure using well log data in Bai Hassan oil A¯Â¬Âelds. To obtain this goal, the formation pore pressure is predicted from well logging data by applying three different methods including the Eaton, the Bowers and the compressibility methods. Predicted results have to show that the best correlation with the measured pressure data must achieved by the modiA¯Â¬Âed Eaton method with Eaton's exponent of about 0.5. Finally, in order to generate the 3D pore pressure model, well-log-based estimated pore pressures from the Eaton method will upscale and distribute throughout the 3D structural grid using a geo statistical approach. The 3D pore pressure model has to show good agreement with the well-log-based estimated pore pressure and the measured pressure obtained from modular formation dynamics tester.

New Test Probe Yields Key Reservoir Answers

Technology Update Extreme downhole conditions pose a challenge to formation testing. Acquisition of accurate reservoir pressure data and high-quality formation fluid samples has proved difficult in cases of low reservoir permeability, extremely viscous crude oil, or unconsolidated formations with poor borehole conditions. Opera-tors have often considered these wells untestable. When testing is possible, it is frequently time consuming and costly with the need to set and cement pipe, shoot perforations, and bring in coiled tubing to run the test. Even then, formation pressure estimates on such wells are frequently inaccurate. However, a new tool has proved able to extend formation testing parameters to extreme formation and borehole conditions. The Saturn 3D radial probe (Fig. 1) developed by Schlumberger is a complementary module to the Modular Formation Dynamics Tester tool. The probe is capable of performing accurate pressure tests in fluid mobilities as low as 0.01 md/cp, and obtaining high-quality fluid samples in mobilities lower than 1 md/cp. In Mexico, a friable sandstone reservoir containing 7.5 °API crude oil in extremely unconsolidated formations was successfully sampled by the 3D radial tool in a very rugose borehole with 12% ovality. The data collected would have been unobtainable with previous test assemblies and was critical for a sub-sequent thermal recovery design. Despite the difficult conditions, the new tool was able to conform to borehole irregularities to achieve and maintain a reliable hydraulic seal. Formation Fluid Challenges Acquiring representative samples of heavy, viscous crude is only part of the story. A North Sea operator took full advantage of downhole fluid analysis (DFA) to characterize viscous, biodegraded oil in a poorly consolidated field. The Catcher area fields, operated by Premier Oil on behalf of colicensees Cairn Energy and Wintershall, contain 300 million bbl of original oil in place, making them one of the most significant recent discoveries in the United Kingdom Continental Shelf. Six wells and three sidetrack boreholes have been drilled to date. The fields are partly characterized by a series of sand injectites, overpressurized sediments that are remobilized and forced upward to intrude into overlying layers. Injected sands are typically characterized by high porosity and high permeability, which is why they are often considered as attractive hydrocarbon targets. However, injectites often range from poorly cemented to unconsolidated, which makes attempts to sample high-quality fluid very challenging.

In situ stress and pore pressure in the Kumano Forearc Basin, offshore SW Honshu from downhole measurements during riser drilling

AbstractIn situ stress and pore pressure are key parameters governing rock deformation, yet direct measurements of these quantities are rare. During Integrated Ocean Drilling Program (IODP) Expedition #319, we drilled through a forearc basin at the Nankai subduction zone and into the underlying accretionary prism. We used the Modular Formation Dynamics Tester tool (MDT) for the first time in IODP to measure in situ minimum stress, pore pressure, and permeability at 11 depths between 729.9 and 1533.9 mbsf. Leak‐off testing at 708.6 mbsf conducted as part of drilling operations provided a second measurement of minimum stress. The MDT campaign included nine single‐probe (SP) tests to measure permeability and in situ pore pressure and two dual‐packer (DP) tests to measure minimum principal stress. Permeabilities defined from the SP tests range from 6.53 × 10−17 to 4.23 × 10−14 m2. Pore fluid pressures are near hydrostatic throughout the section despite rapid sedimentation. This is consistent with the measured hydraulic diffusivity of the sediments and suggests that the forearc basin should not trap overpressures within the upper plate of the subduction zone. Minimum principal stresses are consistently lower than the vertical stress. We estimate the maximum horizontal stress from wellbore failures at the leak‐off test and shallow MDT DP test depths. The results indicate a normal or strike‐slip stress regime, consistent with the observation of abundant active normal faults in the seaward‐most part of the basin, and a general decrease in fault activity in the vicinity of Site C0009.

Use of formation pressure test results over a hydrate interval for long-term production forecasting at the Mount Elbert Gas Hydrate Stratigraphic Test Well, Alaska North Slope: Implications of uncertainties

In the first part of this paper, the pressure and temperature measurements obtained using Schlumberger's Modular Formation Dynamics Tester (MDT) conducted on the C2 interval in the BPXA-DOE-USGS Mount Elbert Gas Hydrate Stratigraphic Test Well (Mount Elbert Well) are history matched, with the following three objectives: (i) to obtain a better understanding of hydrate decomposition and its reformation as conditions cross the p/ T stability, (ii) to obtain formation properties (e.g., permeability) that are consistent with the measurements, and (iii) to explore the non-uniqueness in the history match; i.e., to explore the ranges of parameters that allow a reasonable match of the measured quantities. In the second part of this paper, long-term production performance is predicted, and the effect of the uncertain parameters on the predictions is demonstrated. The results are used to demonstrate the range of long-term production that may be expected, when a model is calibrated using the MDT data. Usefulness of short-term tests for long-term forecast prediction is then discussed.

Prediction of reservoir depletion degree and production GOR using logging-while-drilling data

Abstract Data of logging-while-drilling (LWD) log, formation pressure from MDT (modular formation dynamics tester) measurement, and production performance are used to study the relationship between depletion degree (formation pressure), initial production GOR (gas oil ratio) of single well and LWD response of depletion development in reservoirs. The results indicate that the overlap between density and neutron porosity curves from LWD data are related to reservoir depletion degree and production GOR when the formation pressure is less than the bubble point pressure. Larger overlap between the two curves corresponds to lower formation pressure and higher GOR. The relationship between the formation pressure, production GOR and porosity difference between density and neutron porosities can be derived from multi-analysis and regression. Through the analysis of the actual data from Block II of DLL Oilfield, empirical formulas have been established to predict formation pressure and production GOR from the porosity difference between density and neutron porosities. The predicted results correspond with MDT measurements and production GOR data, which proves the high reliability of the methods.

Two Deepwater GOM Multizone, Frac-Packed, Intelligent Completions

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper OTC 19622, "Case History: Two GOM Multizone, Frac- Packed, Intelligent Deepwater Completions - How Success Was Achieved and the Associated Lessons Learned," by Stephen Jeu and Wayne Cunningham, Thunderbyrd Energy Services; Jacques Braile Salies, SPE, Petrobras America; Richard Jannise, SPE, Brad Beridon, SPE, and Brennan Oubre, Halliburton; and George Arnold, SPE, and Colton Puckett, SPE, WellDynamics, originally prepared for the 2008 Offshore Technology Conference, Houston, 5-8 May. The paper has not been peer reviewed. Deepwater completions are defined as those in water depths greater than 1,500 ft. The extreme depth in itself presents challenges, but in addition to these, operators are seeking completion methods that will increase reliability and flexibility and will eliminate future interventions. The Gulf of Mexico (GOM) is a prime area for deepwater completions, and because of the extensive need for sand control, frac-packed completions have become the norm because they offer reliable sand control and long-term completion efficiency with higher sand-free producing rates and faster reserves recovery. Project Description The Cottonwood deepwater project is in the GOM Garden Banks Block 244, approximately 138 miles south of Louisiana in 2,118 ft of water. The sidetracking of Well B confirmed 130 ft of natural gas and condensate pay. In September 2005, Petrobras America announced an ambitious plan to drill an additional well, complete both wells, install production facilities, and begin production by early 2007, less than 15 months from project sanction. The wells are now Petrobras’ deepest and highest-pressure producing wells worldwide. Gas and condensate production comes from Miocene sands at a depth of more than 19,300 ft. The complex structure and inherent stratigraphy along with the potential for compartmentalization provided multiple challenges for the geoscientists. The many deep and highly pressured reservoirs added further challenges to well-completion success. The reservoir pressure in the G sand in Well A was measured at 15,125 psia, a 15.2-lbm/gal equivalent mud weight. A 15.6-lbm/gal completion brine was used to complete the wells, providing 200 to 250 psi of overbalance. The brine was composed of a blend of zinc bromide (ZnBr2), calcium bromide, and calcium chloride salts, to which 3% potassium chloride was added for improved clay compatibility, along with a corrosion inhibitor and a nonemulsifier. A 213°F bottomhole temperature was recorded with a wireline modular formation-dynamics tester (MDT). Sidewall cores and MDT measurements confirmed that the highly laminated sands had a wide range of permeability, from 5 md to more than 2,000 md; an average of 100 to 200 md was used for completion and frac-pack design purposes. The maximum anticipated shut-in pressure (MASP) at the subsea tree was 11,500 psia and was 13,188 psia at the surface-controlled subsea safety valve (SCSSV) and 10,866 psig at the rig floor during the completion. The high MASP required deployment of the manufacturer's first two 15,000-psi-working-pressure horizontal subsea trees. The trees were installed successfully without significant incident. Fig. 1 shows the two trees.

The Halyard gas discovery: a case study

The Halyard—1 exploration well discovered gas in a new and separate reservoir unit at the top of the Barrow Group along the outer margin of the Barrow Delta. The well is located in WA—13—L, approximately 15 km northwest of the East Spar Field and 4 km east-northeast of the Spar—1 well. It was drilled in February 2008 and intersected 27.8 m of net gas pay in a Valanginian age Barrow Group reservoir interpreted to be a wave-dominated shoreface sandstone. The nearby Spar—1 well was drilled in 1976 and intersected 18.4 m of net gas pay in an older Barrow Group Sandstone within a distinctly separate, delta-front turbidite setting. The Halyard and Spar fields are located within the overall confines of a structural closure at the Top Barrow Formation level. Earlier reservoir models dating back to the 1970s assumed connectivity between all permeable sandstones within the Top Barrow closure. Critical analysis and integration of all subsurface and engineering data sets inclusive of modular formation dynamics tester (MDT) pressures, condensate gas-ratios, production test data, post-drill amplitude variation with offset (AVO) modelling and seismic facies mapping, however, indicate these reservoirs are distinct and separate stratigraphic traps formed by successive, sequentially sealed depositional units within a larger delta slope edge sequence. Collection of this data has yielded considerable insight into what historically have been viewed as simple traps. In our view and experience, the Barrow Group geology is much more complex with many traps typified by critical stratigraphic components in their trapping mechanism. The Halyard discovery is an example of the type of trap we expect to host much of the remaining reserve potential in the proximal Barrow Delta.

Petrophysical evaluation and its application to AVO based on conventional and CMR-MDT logs

Conventional loggings provide the essential data for AVO (Amplitude-Versus-Offset) analysis in rock physics, which can build a bridge linking petrophysics and seismic data. However, if some complex fluid systems, such as serious fluid invasion to formation, low resistivity response or complicated water salinity etc. exist in reservoirs, the conventional logs may fail to provide quality data, leading to calculated errors for elastic properties so worse that the AVO results cannot match the seismic data. To overcome such difficulties in Tertiary reservoirs of Bohai Gulf in China, we utilized both conventional logs and CMR-MDT tool (Combinable Magnetic Resonance and Modular Formation Dynamics Tester) to perform formation evaluation and reservoir descriptions. Our research proposes, it allows petrophysicists to acquire reservoir parameters (e.g. porosity, permeability, water saturation, bound fluids and pore pressure etc), and then these results to combine with core analysis based on laboratory’s measurements to carry out a further rock physics study and AVO analysis in seismic domain.

Fluid inclusion evidence for an early, marine-sourced oil charge prior to gas-condensate migration, Bayu-1, Timor Sea, Australia

The distribution of oil-bearing fluid inclusions (FI) in currently gas-bearing Jurassic reservoir sandstones from Bayu-1 (Northern Bonaparte Basin, Timor Sea) is consistent with the Bayu gas-condensate field originally containing a palaeo-oil column beneath a thick palaeo-gas cap. In order to assess the origin of the oil trapped in the FIs and its relationship, if any, to the gas condensate, a detailed molecular geochemical study was carried out on a FI oil extract and a condensate sample recovered from a similar interval by Modular Formation Dynamics Tester (MDT). Compared to the condensate, the FI oil was generated from a more marine-influenced, less clay-rich source rock or source facies, which was deposited in a less oxic environment with greater eukaryotic input. The source rock of the condensate was more terrigenous and had greater microbial input. The Bayu FI oil contains a greater amount of C 28 and C 29 tricyclic terpanes than the Bayu condensate, and particularly compared to the Elang/Plover sourced oils from further to the northwest (e.g. Corallina and Laminaria), which are more terrestrially-dominated. The Bayu condensate has previously been attributed to either the marine Cretaceous Echuca Shoals Formation, or mixed sourcing from the less terrestrially-influenced facies of the Jurassic Elang and Plover formations, together with the marine Flamingo Group. Analysis of the FI oil confirms a more marine-influenced source facies of the palaeo-oil, with the Echuca Shoals Formation being the most likely source based on oil–oil and oil–source correlations. The FI oil appears to represent a marine source end-member and it is likely that mixing of this oil (sourced from the Echuca Shoals Formation) with hydrocarbons sourced from the more terrestrially dominated Plover/Elang source facies could account for the intermediate composition of the currently reservoired condensate. A discrete ‘Flamingo Group’ is not required and this oil family may not be present in the Bayu area. The differences are nevertheless subtle and a contribution from the Flamingo Group cannot be completely discounted. The FI oil has a mid-oil window maturity (∼0.75% vitrinite reflectance equivalent, VRE), whereas the currently reservoired condensate has a higher maturity (∼0.9% VRE). These maturity data are consistent with early expulsion from the more labile, marine-derived organic matter in the Echuca Shoals Formation, followed by expulsion of large amounts of condensate from the more terrestrially-dominated Elang and Plover formations. Three possible transition mechanisms from gas over oil to condensate are consistent with the FI petrographical and geochemical data. The first charge may have (1) been lost by breaching of the seal, (2) been displaced by the condensate, or (3) been partly dissolved in the later condensate charge. A combination of factors 2 and 3 is considered most likely, but further investigation is required to assess these options. The FI oil at Bayu-1 predominantly represents a different hydrocarbon charge compared to the condensate liquid, and so by analogy the large residual oil columns that are observed elsewhere in the Northern Bonaparte Basin are unlikely to be due to water-washing of a pre-existing gas-condensate column similar to Bayu-Undan.

Determination of Hydrocarbon Properties by Optical Analysis During Wireline Fluid Sampling

Summary Recent innovations in wireline fluid sampling have allowed the expedient recovery of high-quality oil samples. The use of the Optical Fluid Analyzer† (OFA), a part of the Modular Formation Dynamics Tester† (MDT), to predict sample fluid type and quality has now become an essential part of the sampling process. The ability to use the optical data from the OFA in a more quantitative manner has been under development for several years. This paper demonstrates that the analysis of the optical spectra measured downhole can be used to give a quantitative indication of some hydrocarbon properties before or during sampling. Clearly, there are many potential benefits to be gained from using these optical spectra while sampling to assist in reservoir characterization and determination of oil type. Optical data gathered while taking oil samples in 21 wells (drilled with water-based mud) offshore Norway were correlated with the pressure/volume/temperature (PVT) properties of those samples. The samples were selected to ensure a wide range of oil types to establish correlations between the fluid and optical properties. Correlations have been found between the optical response and some fluid properties, as determined from PVT laboratory measurements of the samples. Oil density, saturation pressure (pb), oil compressibility (co), formation volume factor (Bo), and gas/oil ratio (GOR) gave good correlations. Weaker correlations were found with other properties. The GOR and the optical responses could become measured variables with the possible future addition of a GOR measurement sensor to the MDT. Improved correlations are demonstrated when this feature is simulated. The results of this study show that the optical data measured during wireline fluid sampling can help determine key in-situ hydrocarbon properties.