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Imomoh, Victor (Baker Hughes, a GE company) | Ndokwu, Chidi (Baker Hughes, a GE company) | Amadi, Kenneth (Baker Hughes, a GE company) | Toyobo, Oluwaseun (Baker Hughes, a GE company) | Nwabueze, Ikechukwu (Baker Hughes, a GE company) | Okowi, Victor (Baker Hughes, a GE company) | Ajao, Oyekunle (Chevron Nigeria Limited.) | Okeke, Genevieve (Chevron Nigeria Limited.) | Dada, Yemi (Chevron Nigeria Limited.) | Jumbo, Sandison (Chevron Nigeria Limited.) | Aina, Soji (Chevron Nigeria Limited.)
Oil and gas drilling has fully embraced the practice of drilling horizontal and extended-reach wells in place of deviated wells to avoid multi-platform drilling and increase hydrocarbon recovery. However, the producer is still faced with multiple challenges that include lateral facies change, lateral variation in reservoir properties and structural uncertainties. Consequently, it is paramount that continuous advancement is achieved in combining fit-for-purpose, real-time logging-while-drilling (LWD) solutions to assist further in the enhancement of hydrocarbon recovery.
Reservoir navigation services (RNS) involve predicting the geology ahead of the bit to place the wellbore correctly in the zone of interest in a horizontal or near-horizontal path. LWD data, obtained from downhole drilling suites, transmitted in real time through mud pulses to a surface computer where the data are interpreted and used to steer the well in the desired direction. Formation pressure while drilling (FPWD) is a process of acquiring reservoir pressures downhole and this is done with a specialized downhole LWD pressure-testing tool. The use of RNS in Well-MX played a significant role in the drilling project – landing Well-MX in the targeted M reservoir bed and drilling the lateral section. The major geosteering technologies used are the at-bit resistivity and azimuthal propagation resistivity, which provides geostopping capability, reservoir bed boundary mapping and accurate distance to bed boundary calculation. These technologies helped in keeping the wellbore within the hydrocarborn unit of the M reservoir. Performing formation pressure testing in realtime, the team was able to carry out a reservoir gradient analysis which helped with reservoir fluid identification, fluid contact determination, and connectivity of hydrocarbon zones before drilling was concluded.
Well-MX is a horizontal well located in the Mirum field of the Niger Delta Basin, offshore Nigeria. The well was drilled to target the deep multi-lobed M reservoir to a total hole depth of 11,307ft MD. By using Well-MX as a case study, this paper discusses how the combination of reservoir navigation service and real-time formation pressure sampling helped meet drilling objectives for this well. Some of the challenges encountered includes vertical seismic interpretation uncertainty, poor reservoir quality along the drain hole section, change in depth of oil to water contact and undulating bed boundaries. Other challenges and decisions taken to successfully geosteer the well will be reviewed in this paper.
Magnetic resonance (MR) is a very robust service that delivers several formation evaluation products. Both the wireline (WL) and logging-while-drilling (LWD) services deliver shale volume, porosity, permeability, viscosity, saturation and fluid typing. In addition to these, the WL service also delivers capillary pressure and grain size analysis. Although WL and LWD MR Services have different modes of acquisition, the result is usually the same. WL MR uses multiple frequencies, but LWD MR uses a single frequency. Multiple frequencies provide multiple magnetic field gradients that provide for more flexible hydrocarbon typing acquisition sequences, unlike the LWD MR single frequency that supplies a single hydrocarbon acquisition sequence. Dual Wait Time (DTW) analysis is the hydrocarbon typing technique for LWD MR, but the WL hydrocarbon typing has the flexibility to choose from a range of applications that includes two-dimensional MR mapping (2D MR), density multiple wait time (DMTW) analysis, multiple gradient inter-echo spacing (MGTE) analysis, simultaneous inversion of multiple echo trains (SIMET), and T 1 /T 2 ratio (R-T 2) analysis for gas reservoirs.
Oifoghe, Stanley (Baker Hughes, a GE company) | Thern, Holger (Baker Hughes, a GE company) | Coman, Radu (Baker Hughes, a GE company) | Okowi, Victor (Baker Hughes, a GE company) | Sy, Rex (Baker Hughes, a GE company)
Magnetic resonance (MR) logging-while-drilling (LWD) data have numerous petrophysical applications for reservoir characterization. Under certain conditions, a high rate of penetration (ROP) can affect the data quality of MR LWD
Recently, an ROP correction for MR logging data was introduced. The correction on porosity is particularly significant for large volumes of light hydrocarbon (HC) with a large
This paper presents a case study based on MR data recorded offshore Nigeria many years ago. The well was drilled with an ROP exceeding 40 m/h, which was twice as fast as the typically recommended maximum ROP at the time. The logged reservoir has a porosity of 30 to 35 p.u., and it contains light oil and has a high oil saturation. The ROP polarization effect caused a severe porosity overestimation. At that time, no ROP correction was available, and the MR data were considered not suitable for petrophysical interpretation because of the porosity overestimation.
The recently introduced ROP correction was successfully applied to the log data using a constant
Consequently, valuable information can still be extracted from the uncorrected
Magnetic resonance (MR) data were acquired in a six-frequency PoroPerm + Light Oil mode in the study well. The acquired data had a low signal-to-noise ratio from midpoint to the top of the logged interval. This ratio could adversely affect the suitability of this data for hydrocarbon fluid typing and saturation computation.
Examination of the detailed quality control plot showed high B-pulse ringing on the two lowest and the third highest frequencies, A-pulse ringing on the two lowest frequencies, and noise on the two lowest frequencies. The affected frequencies could not be used for fluid typing analysis. The reduction in the total number of available frequencies resulted in a high diffusivity, especially in the gas-bearing reservoir sand. High diffusivity caused some of the movable fluids to appear as irreducible bound water. The low hydrogen index of the gas also caused a low-permeability profile.
Despite the failure of some of the acquired frequencies, there was a need to identify and quantify the fluid type in the reservoir. Several fluid-typing techniques where employed to find a suitable technique for this dataset. After trying Multiple Gradient Inter-Echo Time (MGTE) analysis, the Simultaneous Inversion of Multiple Echo Trains (SIMET) module, and a 2D NMR (
The fluid typing result from
One of the major challenges of Logging-While-Drilling (LWD) Magnetic Resonance data acquisition is its limited logging speed. Typically, LWD Magnetic Resonance is logged at speeds of approximately 20m/hr (65ft/hr). Higher logging speeds will substantially reduce the vertical resolution of the data and prevent full polarization of the Hydrogen Protons in the formation, thus, introducing errors in the measurement of total porosity, fluid fractions, and permeability.
The axial motion (rate of penetration) of the magnetic resonance data has multiple effects on the acquired data. The main effects occur to the data during the polarization time, and the amplitude of the echoes during the Carr-Purcell-Meiboom-Gill (CPMG) pulse sequence time. The effects on the amplitude are broadly referred to as the flow effects.
During the drilling of a well in the Niger Delta, an operator needed to save rig cost by increasing the Rate of Penetration (ROP) for LWD Magnetic Resonance from 20m/hr to 40m/hr. This increased ROP caused an overestimation of the total porosity from magnetic resonance.
A newly introduced correction technique enables the compensation of effects due to high ROP on magnetic resonance data. This ROP correction methodology compensates flow and polarization effects. Total porosity and fluid fractions were corrected, resulting also in an updated Magnetic Resonance permeability index. Validation of the technique was accomplished by an accurate match of the corrected total porosity to results from offset wells.
This paper demonstrates the effect of a high rate of penetration on acquired LWD data. Details of flow and polarization effects, and the procedure for correcting these effects, making the data useable and accurate, are also presented.
The Magnetic Resonance (MR) method is based on a magnetic interaction of the magnetic moments of nuclei and externally applied magnetic fields. In the field of Magnetic Resonance Well Logging, only the hydrogen nuclei are of interest. Hydrocarbon and water contain a large number of hyrodrogen nuclei. The hydrogen nuclei possess the strongest magnetic moment. The hydrogen nucleus is a proton. The proton has a mass, an angular momentum and a charge. A spinning charge creates a magnetic moment. This magnetic moment allows the interaction with magnetic fields.
Due to a high noise-to-signal ratio, 10 of the 24 acquired magnetic resonance echo data logs from a field in the Niger Delta were excluded from the processing result. The reduction in the total number of echoes led to a high diffusivity, especially in the gas-bearing reservoir sand. High diffusivity caused some of the movable fluids to appear as irreducible bound water. The low hydrogen index of the gas also caused a low-permeability profile. The effect of high diffusivity was very prominent in the Apparent Transverse Relaxation Time (T2app) spectrum, but the intrinsic transverse relaxation time (T2intrinsic) spectrum was unaffected. Consequently the, T2intrinsic spectrum was used to determine partial porosities and fractional fluid volumes. However, the total and effective porosities were not seriously impacted.
Gas identification and determination of Gas-Oil Contact (GOC) in reservoirs containing gas and oil can be a major challenge in laminated sand-shale sequences, where the presence of shales drastically affects the response of gamma ray, resistivity, density and neutron logs. Due to the resolution of these measurements, it becomes increasingly difficult to identify and quantify the gas reservoirs. In a West Africa offshore well in a Cretaceous formation, using a Penta-Combo Bore Hole Assembly (BHA) with basic Formation Evaluation (FE) measurements, the use of additional services such as Nuclear Magnetic Resonance (NMR) and Formation Pressure Tester Logging While Drilling (LWD) services, significantly improved the confidence in interpretation of the reservoir fluids. In the example well, though the size of the density-neutron crossover showed a reduction in the oil zone as compared to the gas zone to a certain degree, the actual position of the Gas/Oil contact and the reservoir fluid saturation were not certain. Using the traditional NMR porosity undercall in gas zones as well as the dual wait time (DTW) tranverse relaxation time (T 2) distribution analysis, the gas zone was confirmed and the saturation of each of the fluids in the reservoir was accurately determined. The NMR tool was programmed to acquire data in dual wait time (DTW) mode to calculate hydrocarbon saturation. The Magnetic Resonance Dual Wait Time (DTW) approach takes advantage of Longitudinal Relaxation Time (T 1) contrast to solve for hydrocarbon saturation. "In light hydrocarbons, in a water-wetting reservoir, the hydrogen atoms in the hydrocarbon fluid relax slower than the nonmovable and movable water. By using two polarization or wait times (T w), it is possible to calculate hydrocarbon saturation using magnetic resonance tools" (Thorsen et al., 2008,).
Kim, Yonghwee (Baker Hughes) | Boyle, Keith (Chevron) | Chace, David (Baker Hughes) | Akagbosu, Pius (Baker Hughes) | Oyegwa, Akomeno (Chevron) | Wyatt, Dennis (Chevron) | Okowi, Victor (Baker Hughes) | Gade, Sandeep (Baker Hughes)
Monitoring fluid saturations in a producing reservoir over time is critical for the effective exploitation of the resources. This can be complex in a two-phase system and is exacerbated when changes in the gas cap due to depletion or contraction, due to re-pressurization from water injection, have to be considered. Consequently, a three-phase reservoir fluid saturation measurement is crucial in determining the future of the reservoir and if remedial actions must be taken for overall optimization of the reservoir’s production.
To answer this challenge an advanced salinity-independent method that combines the carbon/ oxygen (C/O) analysis with gamma ray ratio-based gas saturation techniques has been developed to deliver three-phase fluid saturations. In this new method, C/O analysis and a gamma ray ratio-based gas saturation method are incorporated using an innovative triangulation technique to simultaneously quantify water, oil and gas saturations. Well-specific Monte Carlo N-Particle (MCNP)-based forward modeling enables pre-job sensitivity analysis and provides the predicted theoretical measurement responses required for log quality checks and formation evaluation in data postprocessing.
This paper describes a collaborative effort by an operator and a service company to evaluate the new three-phase formation fluid saturation analysis technique to obtain post-production fluid contact and saturation in a mature field in Nigeria that was put on production in the early 1970s. In this particular well-logging campaign, the objective was to estimate the current hydrocarbon saturation.
Because the formation water salinity of the subject field was low (typically less than 15,000 ppm NaCl equivalent), C/O and inelastic gamma ray ratio measurements were acquired. The new triangulation method was used to integrate these measurements to provide salinity-independent three-phase fluid saturations. Results from example wells analyzed using the new technique are presented.
The Niger delta sedimentary basin is a depositional complex of Cenozoic-aged sand and shales that extend from an approximate of longitude 3° to 9° east and latitude 4° 30' to 5° 20' north. This delta is characterized by progradation, rapid sedimentation, continual loading of sediments and gravity-driven syn-depositional deformations. Hydrocarbon exploration in the Niger delta started in 1937, mainly onshore. Exploration and production now extends offshore.
Given the enormous resources that go into drilling a well, the objective is to get it right the first time (especially when drilling high-angle and horizontal wells with their associated problems of true vertical depth uncertainty and resolution of surface seismic). In drainhole sections, geological uncertainty and production technology pushes geo-steering to the limits. Sometimes, these challenges put forward questions such as: is the reservoir faulted, compartmentalized, thin, undulating or show vertical lithological changes; how far from the roof must the trajectory be; what is the minimum required drain length; and how much dogleg is acceptable?
To achieve success in the reservoir navigation of any well, some success factors must be considered: the drilling strategy, available downhole tool (drilling system and formation evaluation), surface software, personnel and communication protocol. This paper examines these success factors using the example of Well-X. The goal is to bring more understanding to the procedures involved in reservoir navigation, the challenges posed by geology, the factors to consider when planning a modern geo-steering job, the importance of teamwork, the benefits of integrated interpretation and the value communication brings to the entire process.
Ndokwu, Chidi (Baker Hughes) | Okowi, Victor (Baker Hughes) | Foekema, Nico (Baker Hughes) | Caudroit, Jerome (Addax Petroleum Development) | Jefford, Leigh (Addax Petroleum Development) | Otevwe, Joseph (Addax Petroleum Development) | Fang, Xiaodong (Addax Petroleum Development) | Idris, Maaji (Addax Petroleum Development)
High-angle or horizontal wells pose many geological challenges that include maintaining well trajectory within a particular horizon in drain sections, detecting stratigraphic positions after passing a discontinuity, and subsurface feature identification. Geo-steering has shown increased value over the years because it uses data from different sources, including borehole imaging, to meet these challenges. Bulk density and gamma ray borehole images can be used to describe the near-wellbore environment, and that description can be analyzed further to explain the near-wellbore structural geology. In this study, structural analysis and zonation of bulk density and gamma ray images were used to detect the fault zone, while a geo-steering application was used to pick the true stratigraphic depth after crossing the fault. Provision of an alternative model to seismic-only interpretations and a better understanding of subsurface structures are the industrial benefits of this study.
The Niger delta sedimentary basin of Southern Nigeria is a prograding depositional complex of Cenozoic-aged sand and shales that extends from about longitude 3° – 9° E and latitude 4° 30' – 5° 20' N. This paper demonstrates the importance of geo-steering, shows the application of geo-steering in a high-angle well drilled in the Niger delta sedimentary basin, and establishes the importance of structural analysis from borehole images in making final geo-steering interpretations. This paper also shows that borehole imaging is an additional and useful source of information in the planning stage of any drilling campaign.