Reddy, S. S. (Oil and Natural Gas Ltd) | Anjaneyulu, J. V. (Oil and Natural Gas Ltd) | Lal, Abhay Kumar (Oil and Natural Gas Ltd) | Rao, E. J. (Oil and Natural Gas Ltd) | C H, Ramakrishna (Oil and Natural Gas Ltd) | Talreja, Rahul (Schlumberger) | Bahuguna, Somesh (Schlumberger) | Zacharia, Joseph (Schlumberger) | Chatterjee, Chandreyi (Schlumberger) | Basu, Jayanta (Schlumberger)
Malleswaram field in Krishna-Godavari (KG) basin has proven gas reserves in the late Cretaceous Nandigama formation. Many drilling challenges were faced, including losses, tight hole, and stuck pipe in the Raghavapuram and Nandigama formations overlying the reservoir interval. This study was conducted to provide a solution for drilling optimization by mitigating drilling-related nonproductive time (NPT). Integration of acoustic and geochemical data for geomechanics study provided a new insight into cause of overpressure and need for revamping of casing policy to significantly improve wellbore stability, mitigate risks, and ensure future drilling success. Generated stress models can be used to optimize hydraulic fracturing in these reservoirs. A completion quality based on stress model indicates the need for multistage fracturing due to the presence of stress barriers inside sand units in Nandigama formation.
In a horizontal well, apparent resistivity curves often show varied separations and increased values due to the polarization horn effects near a boundary and other effects such as adjacent beds or anisotropy. The true formation resistivity (Rt) is uncertain and can be mis-interpreted. As a consequence, saturation estimates are uncertain so that the reserves cannot be accurately predicted. A full inversion can be used to derive the true Rt. However, the instability of an inversion due to the lack of measurement variation along the measured depth makes the Rt derivation very challenging.
To determine a true Rt from the logging-while-drilling (LWD) resistivity measurements, a general full inversion is usually time-consuming and needs some inputs on formation model. This paper presents an alternative approach to derive the true Rt without input of any prior information. The alternative approach uses a simple two-layer model for the removal of horn effects and derives a solution at two steps: a) inverting resistivities of the two layers at each distance away from the boundary; b) selecting a solution with specific constraints such as using statistics in a moving window and internally consistent physical constraints to make the solution more reliable. In the first step, neural networks are developed to calculate tool responses and derivatives for the savings of computation time and memory needs.
Synthetic examples show that true Rt can be recovered when the relative dip between a borehole and a layered formation is greater than 85 degrees. The examples show that bed boundaries can be reproduced with sufficient accuracy by our approach, among others to define pay zone intervals. In addition, the resolution of the method was studied with models of different layer thicknesses and is discussed in details in the paper. As an outcome, the derived true Rt reads lower in a resistive thinner layer and reads slightly higher in a conductive thinner layer. A field example from a North Sea oil field demonstrates very promising and robust Rt results from the method.
The inversion is fully automatic and can be used in real time and downhole. Physical constraints that are special to a horizontal well and better strategies make our algorithm robust and very fast.
Development of source-rock resources relies on the rigorous knowledge of their petrophysical properties such as porosity, permeability, and hydrocarbon saturation. In parallel, a concise description of the wettability and pore structures is commended. This paper presents a detailed Nuclear Magnetic Resonance (NMR) T2 study of the wetting characteristics and pore structure in organic-rich source rocks from different locations including the Eagle Ford formation. Although these rocks are highly laminated and calcite dominated, our studies indicated that they have distinct different pore structure and connectivity, and differ in how TOC is dispersed within the rock fabric. We believe that the entailed findings could influence our thinking on how best to produce these shales, wellbore stability, drilling fluid selection and other asset development actions.
Source-rock samples with varied amount of total organic content (TOC) were drilled perpendicular or parallel to the laminations. The samples were cut into twin plugs which were sequentially saturated by spontaneous imbibition of 5% KCl brine and diesel (oil). The NMR T2 measurements were used to determine the fluid imbibition rate and amount, as well as the porosity associated with organic and inorganic components of the source rocks. The fracture apertures were obtained via an application of characteristic T2 cutoff times to the NMR T2 distributions. The mineral elements, phases and TOC of the rocks were measured using X-ray Fluorescence (XRF), X-ray Diffraction (XRD) and HAWK pyrolysis, respectively.
The prevalence of surface relaxation on the NMR dynamics was prominent as the transverse relaxation took place at time scales (T2 ≤ 100 ms) much shorter than their bulk values. The overall wettability of the samples showed a mixed character as the brine and the oil had been intimately imbibed. Nevertheless, the details of the wetting behavior of the Eagle ford samples and the other samples were different. For instance, Eagle Ford samples imbibed larger volumes of brine and faster than oil, on the contrary the other samples imbibed larger volumes of oil and faster than brine.
The apparent preference of oil on the other samples is attributed to their high TOC compared to the Eagle Ford samples. Upon imbibition in these samples, brine is observed to flow along the clay rich bedding planes. In fact, the interaction between brine and clay is identified to be the potential driver of the rock stability problems especially near the wellbore; however it is constrained by the type of residing clays. The discrepancies in the wetting traits are magnified by the presence of fractures which enhanced the network connectivity of both hydrophobic and hydrophilic pores or even across them. Furthermore, the fractures allowed the fluids to surpass the vertical bedding planes and thus accelerating the fluid distribution processes inside the pore space. The fracture apertures were found to range from 1 μm to 15 μm which are typical values for source rocks (
Verma, Chandresh (Saudi Aramco) | ElKawass, Amir A. (Saudi Aramco) | Mehrdad, Nadem (Saudi Aramco) | ElDeeb, Tarek (Saudi Aramco) | Qazi, Muhammad Q. (Saudi Aramco) | Galaby, Amir (Schlumberger) | Salaheldin, Ahmed (Schlumberger) | Fakih, Abdulqawi Al (Schlumberger) | Osman, Ahmed (Schlumberger) | Hammoutene, Cherif (Schlumberger)
While ERD multi-lateral wells in a large Middle East field are typically drilled in six to seven well bore sections, drilling the 8.5-in curve and the 6.125-in lateral sections represents more than 50 % of the total time spent drilling the well. Challenges while drilling the curve section with a motor include difficulty transferring weight to the bit while sliding and differential sticking in the highly poros zones of gas cap. The laterals, which can extend up to 12,500 ft of reservoir contact, are characterized by medium to hard compacted carbonate formations with high stick and slip tendency. This represents several challenges for drill-bit design engineers given that aggressive cutting structures are preferred to generate good rate of penetration even though this often leads to high bottom-hole assembly vibration. Trajectory control, hole cleaning and long circulating hours also represent significant challenges.
This paper will present details of the engineering analysis performed to optimize both 8.5-in and 6.125-in wellbore sections.
For the curve section, the first step was to change the drill string from 5 in to 4 in which considerably reduced the time taken to change the string prior to drilling the laterals. This change of drill string was accompanied by the use of a rotary steerable system and a PDC bit. This was a combination that had never been implemented since the field discovery in 1968. These changes resulted in performance improvements in excess of 50 %.
For the laterals, the engineering analysis resulted in the need of a completely new bit design. The cutting structure was modified to provide a more aggressive bit to formation interaction, and the gauge contact with the formation was enhanced to maintain the bit and BHA stability. The resulting design broke the field rotary steerable ROP record by 28 %. The bit drilled the highest single run footage in the field (12,698 ft) at the highest ROP (96.93 ft/hr) with a rotary steerable system. This was further complemented by optimizing the drilling practices and well bore cleaning practices allowing the elimination of several conditioning trips within the long laterals which resulted in three days of savings in a three lateral well.
The paper will conclude with a discussion regarding the reduced injury exposure that resulted from changing the drill string earlier within the well and a review of further improvement opportunities.
Du, Juan (State Key Laboratory of Shale Oil and Gas Enrichment Mechanisms and Effective Development, Sinopec Research Institute of Petroleum Engineering) | Pang, Wei (State Key Laboratory of Shale Oil and Gas Enrichment Mechanisms and Effective Development, Sinopec Research Institute of Petroleum Engineering) | Lei, Jun (No.1 Oil Production Plant, PetroChina Daqing Oilfield) | Zhang, Tongyi (State Key Laboratory of Shale Oil and Gas Enrichment Mechanisms and Effective Development, Sinopec Research Institute of Petroleum Engineering) | Ehlig-Economides, Christine A. (University of Houston)
Uniform fractures with equal half-length and fracture spacing are commonly assumed when conducting pressure transient analysis and production performance estimation for shale gas wells. However, production loggings and microseismic in many shale gas wells illustrate that only about one third to one half of hydraulic fractures produces. Meanwhile, the productive fractures usually contribute quite differently to the production rate. Therefore, modeling and analyzing of non-uniform fractures properties like fracture type, half-length and fracture spacing are of great importance to understand hydraulic fractures' effect on dynamic flow regimes, pressure and production performance.
In this paper, one model with non-uniform fracture properties is used combing shale gas properties like desorption, pressure dependent permeability and fracture properties like un-even distance, un-even half-length. Type-curves of interpretation models with un-uniform facture and the ones with uniform fractures are compared. Rate normalized pressure (RNP) method is used to analyze non-uniform fractures' effect on shale gas wells' flow regimes and drainage volume.
Parametric analyses for five reservoir parameters and six well & fractures parameters are conducted. The reservoir parameters include reservoir permeability, porosity, pressure dependent permeability (PDP), desorption and Outer boundary area. The well and fracture parameters include clustered fracturing and evenly spaced fracturing with fixed total fracture half-length (TFH), fracture half-length, cluster spacing, cluster number per stage, stage number with fixed TFH, stage number with fixed fracture half-length.
Results show that a series of flow regimes including three linear flows and three pseudo-steady state flows can be diagnosed for shale gas wells with non-uniform fractures. Three pseudo-steady state flows correspond to flow within stage volume, flow within stage plus space between stages volume, and flow within SRV separately. However, the flow regimes reflecting stage volume is missed for shale gas wells with uniform fractures. Permeability determines when the three pseudo-steady state flows happens, but doesn't change the related three volumes. Desorption doesn't change the shape of the pressure and pressure derivative curve, and it only changes the apparent drainage volume. PDP impose severe effect on shale gas well's pressure drawdown and apparent drainage volumes. Increasing the modulus results in decrease of the apparent volume being drained especially when the modulus is larger than 0.01MPa-1. Evenly spaced fracturing has lower pressure derivative and pressure drawdown than non-uniform fracturing, which means it can yield more gas production for the same amount of injected propant and fluids. Fewer stages fractures with longer half-length have lower pressure derivative and pressure drawdown, and will reach SRV boundary earlier than more stages fractures.
There is a lack of comprehensive simulation tools that (a) accommodate the complexities of advanced completions together with near-wellbore behavior and that (b) have reliable wax-precipitation models for production planning. In this work, these issues are tackled by combining three specific models. First, a steady-state, three-phase, nonisothermal flow model in advanced horizontal completions was implemented to run fluid-specific simulations, thereby calculating field-specific flow conditions. This is useful in situations when fluid-specific temperature calculations are important, such as wax crystallization. Second, a nonisothermal, vertical flow model was developed by combining Hagedorn and Brown's multiphase-flow correlation with Ramey's multiphase-temperature model by solving them in sequence (iteratively). The advanced horizontal-well model and vertical flow model were coupled iteratively at the bottom hole where the two models meet. Third, two different analytical wax-crystallization models were incorporated in the aforementioned coupled flow simulator to calculate the location of wax precipitation along the vertical section of the well. These three simulation models, individually and in combinations, were tested and found to be in par with theory, expectations, and published results. In addition, a significant difference was noted between Ramey's analytical temperature profile (which is a widely used approximation) and the complete Ramey's model integrated with the simulator developed in this work.
Mnich, Cheryl (ConocoPhillips (U.K.) Ltd.) | Bisain, Amarjit (Schlumberger) | Perna, Ferdinando (Schlumberger) | Mearns, Leanne (ConocoPhillips (U.K.) Ltd.) | Saputra, Eky (ConocoPhillips (U.K.) Ltd.) | Anderson, Callum (ConocoPhillips (U.K.) Ltd.) | Dupuis, Christophe (Schlumberger)
In 2014 ConocoPhillips (U.K) Ltd. drilled a third development well, a horizontal infill, in the Brodgar gas condensate field (central North Sea) to target a low relief structure 6,000 ft west of the existing production wells. A new deep resistivity tool was successfully used in this well to aid geosteering and mapping of the hydrocarbon envelope.
A pilot well was originally proposed to reduce uncertainty around the hydrocarbon-water contact (HWC) and the top structure depth at the target location. However during data acquisition planning, extensive simulations of the response of the deep directional resistivity (DDR) logging-while-drilling (LWD) tool were carried out to evaluate its capability to reduce these uncertainties. The simulations gave confidence in the ability of the DDR tool to: (1) detect the reservoir 50 ft true vertical depth (TVD) away before wellbore arrives at top reservoir; and (2) effectively map the top and base of the entire reservoir zone. The decision was made to drop the pilot well and apply this new technology to mitigate the risks and meet the well plan and production objectives. This decision was supported by detailed reservoir simulation work and uncertainty modelling.
The tool response showed the range of hydrocarbon column height upon landing at the initial target location to be between 70 and 110 ft (mid case predrill simulations predicted a column of 104 ft). Due to mechanical issues, this initial wellbore had to be abandoned and sidetracked at the 13 3/8-in shoe. As the sidetrack was a twin of the abandoned hole, the DDR LWD tool was not required for landing the sidetrack but was used for geosteering the horizontal section. The tool provided a real-time resistivity profile that could be interpreted up to 80 ft above and below the wellbore resulting in an accurate "map" of the hydrocarbon envelope. The tool has helped to significantly reduce uncertainty on top structure depth and on water encroachment behaviour, leading to re-interpretation of the seismic, static, and dynamic models.
For ConocoPhillips (U.K) Ltd. this case study has demonstrated the value of applying new technology to reduce subsurface uncertainties and eliminate unnecessary well cost.
Typical rock berms used to protect submarine pipelines may be damaged under shear by a first year grounded ice rubble keel. Physical model tests in a centrifuge have indicated that such damage occurs under loads less than those typical of actual design conditions. These novel tests have reproduced both failures of the rock berm and identified failure criteria for the ice rubble. The tests are of a preliminary nature given the discrete, rather than continuum, nature of the interaction event. The model freshwater ice rubble behaved as a frictional granular material under the shear test conditions with a peak friction angle of 38 degrees. Measured ice rubble shear strengths exceeded 65 kPa.
First year freshwater ice rubble large scale tests were conducted as part of the Pipeline Ice Risk Assessment and Mitigation (PIRAM) and Development of Ice Ridge Keel Strength (DIRKS) Joint Industry Projects. New finite element analyses of the PIRAM test set up indicate the boundary constraints on the test results. The measured PIRAM ice rubble shear strengths exceeded 35 kPa.
The first two test series indicate that ice rubble shear strength may exceed currently accepted design limits.
The Development of Ice Ridge Keel Strengths is a four-year collaborative venture between the C–CORE Centre for Arctic Resource Development (CARD) and the National Research Council – Ocean, Coastal & River Engineering (NRC-OCRE). The main focus of the project is to investigate the failure mechanisms associated with gouging ice ridge keels and the conditions under which these keels will continue to gouge without failure. This is important for the design of subsea structures in shallow waters, where ice keels have been observed to scour the sea floor, posing a threat to pipelines and subsea infrastructure. A series of near full-scale keel-gouge tests were carried out to investigate the strength characteristics of a first-year ice keel and its subsequent failure as it was pushed into an artificial seabed. The ice keels were constructed using freshwater ice blocks with a nominal thickness of 10 cm, produced in a cold storage facility prior to the start of the test program. The ice keels were constructed with the aid of a keel former that produced idealized keel geometries of 1.7 m depth, 4 m length and 3.5 m width. Once constructed, the keels were lowered into the water and left overnight to consolidate with air temperatures held at -20°C. The keel samples were tested using a custom-built frame that was designed and used in the Pipeline Ice Risk Assessment and Mitigation (PIRAM) Joint Industry Project. The frame applied a vertical surcharge load to the top of the keel whilst a soil tray was displaced horizontally, causing the bottom of the ice keel to interact with an artificial seabed. A total of ten keel tests were conducted in this test program. The parameters varied were the initial temperature of the ice (-3° and -18°C), the initial surcharge pressure (5-60 kPa), the soil tray velocity (1-20 mm s-1) and the consolidation time (19-48 hrs). An overview of the test program and preliminary results are discussed.
A new riser concept is proposed by Subsea 7 for field development in deep and ultradeep waters: the Tethered Catenary Riser (TCR)-patent pending. The concept consists of a number of steel catenary risers supported by a subsurface buoy which is tethered down to sea-bed by means of a single pipe tendon and anchored by means of a suction pile; flexible jumpers are used to make the connection between the Floating production Unit (FPU) and the buoy. Umbilicals run without interruption from the FPU to their subsea end while being supported by the buoy.
The system has all the advantages of de-coupled riser arrangements: flexible jumpers effectively absorb platform motions, thereby the rigid risers and tendon have very small dynamic excitation. The system can be installed before FPU arrival on site, which improves the time before first oil. Analyses have shown that, with adequate geometry of the buoy, the latter is sufficient stable to induce acceptable tilt and twist when different arrangements of SCRs and flexible jumpers are installed, and under accidental scenarios during the in-place life.
The riser system is best designed for a number of risers between 4 and 8, in addition to a number of umbilicals, thus convenient for one or two drilling centers.
Results of the basic engineering work on the TCR clearly indicate that it is possible to have a robust design using presently qualified materials and technology. The components used in the TCR are all field proven as they are commonly used in existing riser systems.
As a result of installation studies, a method very similar to the one commonly used by Subea7 for Single Hybrid Risers (SHRs) has been selected for the buoy and tether system. Placement of rigid risers, jumpers and umbilicals is as done by Subsea 7 for the BSRs. This method is well adapted for installation by the new Subsea 7 flagship vessel Seven Borealis which is able to perform heavy lift and pipe laying.
The Tether Catenary Riser is a credible option for use in deep water developments all over the world. Since all the components, design methods and installation procedures are fully qualified and familiar to Subsea 7, the concept is cost effective and ready for project application.