Asia's first rigless subsea stimulation was executed in 2018, with intervention performed upon three target wells offshore Sabah Malaysia, at a water depth of approximately 1400 m (4,593 ft). Significant changes in reservoir performance prompted an acid stimulation and scale squeeze treatment, designed to remedy fines migration and scaling issues within the well and production system. Treatment fluids were delivered subsea by an open-water hydraulic access system, using a hybrid coiled-tubing downline. Access to the subsea trees was permitted via a patented choke access technology, allowing for a flexible, opex-efficient, and low-risk intervention. The intervention system was installed upon a multi-service vessel, with the downline deployed via the vessel moonpool. A second support vessel was used as required to provide additional fluid capacity without disturbing primary intervention operations. This enhanced the flexibility of the operation, permitting changes in the treatment plan to be accommodated for without impact to critical path stimulation activities.
The full intervention was delivered as an integrated service, with all elements supplied by a single provider, via one contract. An established network of in-house equipment, expertise, test laboratories, and operational bases supported the planning and execution of the project. This was complemented by select external providers for vessels, remotely operated vehicle services, and other specialist contractors.
The challenges faced during this new market entry included completion of a comprehensive treatment fluid test program, importation and logistics of equipment from around the globe, and managing operational risks, all within a condensed timeline to satisfy a brief intervention window. By leveraging the diverse global network of the service provider, the technology and people required for the project were accessed and brought together to achieve a collaborative solution. This was enhanced by the inclusion of performance based elements within the contract. The provision of a highly efficient and flexible well access technology also supported rapid mobilization and operational risk reduction.
Post-stimulation well testing confirmed an average increase in oil productivity of 86%, with a corresponding productivity index factor (PIF) gain of 3.4. These results, combined with the efficient execution of the campaign, confirm the appropriateness of open-water hydraulic access using coiled-tubing for performing cost-effective stimulations on complex subsea wells.
Successful entry to the region was highly dependent upon the integrated nature of the service. Access to the service providers global network permitted a high degree of influence upon the ultimate performance of the stimulation. Examples include the PIF results achieved and the responsive actions taken to remedy offshore challenges such as reservoir lock-up on well #3.
Liang, Xing (PetroChina Zhejiang Oilfield) | Wang, Gao-Cheng (PetroChina Zhejiang Oilfield) | Pan, Feng (Schlumberger) | Rui, Yun (PetroChina Zhejiang Oilfield) | Wang, Yue (Schlumberger) | Zhang, Lei (PetroChina Zhejiang Oilfield) | Mei, Jue (PetroChina Zhejiang Oilfield) | Li, Kai-Xuan (Schlumberger) | Zhao, Hai-Peng (Schlumberger)
Understanding mineral composition and depositional mechanisms aids in evaluating gas in place and mechanical properties of shale reservoirs. A method developed to delineate mineral variations and depositional setting combines borehole elemental concentration logs with borehole electrical image logs. Borehole elemental concentration logs provide a continuous measurement of the concentrations of more than 20 elements, which data help in obtaining quantities of mineralogical constituents. Electrical borehole images are used to identify in situ depositional features. Regional mapping of variations of mineral constituents and depositional features indicates sedimentary facies distribution.
The Lower and Upper WuFeng-LongMaxi Formation was studied in 27 wells spanning 100 km west-east across the southern SiChuan basin. From elemental spectroscopy, argillaceous, carbonate, and siliceous lithologies were identified; these were examined by scanning electron microscope (SEM) to investigate their mineralogy and geological origin. Argillaceous minerals were primarily supplied by terrigenous sediments, the majority of carbonate minerals originated from chemical precipitation, and siliceous minerals are associated with siliceous-shell organisms in the Lower WuFeng-LongMaxi strata and terrigenous influx in the Upper LongMaxi strata. A transgressive lag occurring at the base of the WuFeng formation corresponds to carbonate pebbles in cores and bedding-parallel gravels on borehole images. Silty layers deposited by turbidity currents that mainly appear in Upper LongMaxi Formation were readily identified on borehole images.
Shale gas condensate is known to form more readily in smaller than larger pores at the same reservoir conditions and can reduce the mobility of the gaseous phase significantly not only in individual pores but also in a pore system, to limit gas production. To investigate the interplay of fluid confinement factors on effective gas flow behaviors in shale, in this work we developed a new phase equilibrium calculation algorithm for evaluating phase properties in pores of variable sizes and a shale-gas pore-network model. We coupled them into a workflow to study the effect of shale gas condensate on the gas permeability on selected pore networks, considering an empirical criterion of condensate pore bridging and gas flow and transport mechanisms.
The workflow makes use of Soave-Redlich–Kwong (SRK) EOS to model the fluid phase behavior, Zuo and Stenby's parachor based method to predict IFT and Pedersen's corresponding state model to predict viscosity by an iterative procedure underpinned by a modified negative flash algorithm. For any given pore network, this procedure is applied to calculate a full set of PVT properties for any confined reservoir fluid and to evaluate pore-bridging criterion for each and every pore element in the network before performing pore-network gas flow simulation. The pore network model is implemented to simulate the real gas flow in nanoscale porous media, taking into account the contributions from non-Darcy flow, adsorption, surface diffusion, and the formation of condensate bridges.
Using an Eagle Ford gas condensate sample, this study shows that the decreasing pore size has led to an increase in condensate dropouts in a nanoscale single cylindrical pore. The condensate liquid has moderately higher PVT properties compared to the gas phase. The differences of those properties between condensate and gas phases become smaller with the decrement of pore size. This trend appears to be opposite to those of a non-confined fluid in which condensate drops out due to pressure depletion. It has implied that the fluid confinement effect causes less flow resistance than pressure deletion even if the amount of dropouts are the same. The roles of both the pore space confinement and topology were examined on representative models. The results from the simulations on uniform pore networks show gas adsorption and surface diffusion have opposite effects and result in a minor net negative impact to the apparent permeability even when pore radius is less than 50 nm. The simulation results on a regular pore network with randomly distributed pore size show there is only a limit impact on apparent permeability as a result of condensate bridging in small pores, but with an increase in tortuosity, this impact increases.
Distributed vibration sensing has provided a new measurement technique for monitoring hydraulic fracture treatments. We demonstrate that successful existing approaches that integrate pumping parameters and microseismic observations with complex fracture simulation and 3D mechanical earth modelling can be extended to incorporate distributed strain, vibration and flow allocation providing a highly constrained interpretation.
In a monitoring well, where we deploy a hybrid borehole geophone array of 3C geophones for accurate microseismic events mapping, we additionally recover a signal related to static strain from the lowest vibration frequencies of the fibre. From this hybrid cable composed of fiber interconnects and 3C geophones, we may recover extended-aperture information (i) to supplement the geophone-acquired data at microseismic frequencies, (ii) to better constrain hypocenter determination and associated characteristics (e.g., source parameters, attributes, rock failure mechanisms). Furthermore, deploying a fiber within the treatment well, we can recover the relative flow split between the perforation clusters, obtain the bottom hole pressure using the attenuation of the pump harmonics, etc. We integrate these new measurements into the existing geomechanical modelling approach to stimulation interpretation.
We present an example of job planning where synthetic fiber vibrations at the full frequency range and pump data as well as geophone responses are created based on geomechanical and geophysical simulation.
Malpani, Raj (Schlumberger) | Alimahomed, Farhan (Schlumberger) | Defeu, Cyrille (Schlumberger) | Green, Larrez (MDC Texas Energy) | Alimahomed, Adnan (MDC Texas Energy) | Valle, Laine (MDC Texas Energy) | Entzminger, David (MDC Texas Energy) | Tovar, David (Schlumberger)
As well density in a section increases, drilling and completions decisions regarding the stimulation of infill wells are increasingly informed by changes in the in-situ stress, mechanical properties, and material balance that result from depletion around parent wells. This is a multifaceted reservoir-dependent four-dimensional problem with many different dependencies. Accordingly, projects involving parent-child interactions during the completion phase are carefully planned using sound engineering principles to avoid negative effects of depletion and fracture hits. We present a case study from a section development in the Wolfcamp formation. Multiple wells drilled at various times are chronologically described below:
1) Parent well in the middle of the section – generation I
2) Child well 1 to the western edge of the section (2 months after parent well) – generation II
3) Child well 2 to the eastern edge of the section (2 months after child well 1) – generation II
4) Child well 3A between parent well and child well 1 (6 months after child well 2) – generation III
5) Child wells 3B, 3C, and 3D (drilled from the same pad) between parent well and child 2 (6 months after child well 2) – generation III
All wells but child 3D are in the same horizon. Downhole and surface gauges were installed on all observation wells during the completion infill wells (child 3A, 3B, 3C, and 3D). Water injection treatment was performed on the existing wells (parent, child 1, and child 2) wells prior to completing generation III infill wells. Child well 3A was completed first to build up pressure on the west side of the section. Child wells 3B, 3C, and 3D were from same pad on the surface and were zipper fractured. Design changes were made to the completion program with contingencies built-in to make additional changes on the fly to incorporate field geometry control aids and reduction to injection rate and fluid volume.
The parent well experienced fracture hits during completion of child 1 and child 2, spaced at ~2,500 ft. Chemical tracers and production behavior suggested that even a few months of production led to pressure reduction in the section. During completion of child wells 3A, 3B, 3C, and 3D, multiple pressure increases were observed on the parent and child 2 wells with varying degree of severity, but no fracture hit. The stress buffer (shadow) created by carefully sequencing the stimulation program aided in reducing the fracture communication. The fluid injection strategy was effective in reducing the magnitude of pressure communication. Additionally, an active pressure-monitoring program and real-time design changes were able to prevent fracture hits.
The tracer data and productivity index (PI) profile suggest that during stimulation, wells have been hydraulically connected; even though the connections fade over time, results in overall of lowering of reservoir pressure. Some sections do show abnormal behavior likely due to localize geological features. The initial PI for the child 3A, child 3B, and child 3C is smaller than that of the parent well, like child 1 and child 2 wells. All wells in Wolfcamp A shows similar PI profile after all the wells were put back on production, except for child 3A. Child 3D well (Wolfcamp B) has higher PI than other generation III wells pointing to no or minimal communication between the two formations. The infill wells (generation III) have increased water cut than the existing wells (generations I and II). Child 3D well is in Wolfcamp B, which has higher water saturation as compared to Wolfcamp A in the area.
Wells with spacing above 1,000 ft show equivalent productivity, but wells less than 500 ft apart show inferior productivity. The optimum well spacing with the general completion and stimulation design in the area seems to be within 500 ft to 1,000 ft (5 to 10 wells in a section) in this area in Wolfcamp A. The results also suggest that hydraulic connectivity from Wolfcamp B to Wolfcamp A but the production seems to be isolated from Wolfcamp A. Developing a section with depletion effects occurring at various distances and durations is challenging. Our proactive approach of designing, monitoring, and responding provides insights into the development of multigeneration wells in the Wolfcamp formation and in similar settings around the world.
The East Duvernay shale basin is the newest addition to the list of prolific reservoirs in Western Canada. Over the last 3 years, horizontal drilling and multistage hydraulic fracturing have increased significantly. Because much of the play is still relatively new, much of the drilling has been limited to single wells or two wells per pad. Due to the low permeability of the matrix, hydraulic fracturing is required to unlock the full potential of the East Duvernay field. Because geomechanics is a critical factor in determining the effectiveness of hydraulic fracture propagation, we examined how varying the pore pressure profiles affects modeled in situ stresses, hydraulic fracture geometries, and overall field optimization.
The pore pressure varies across the East Duvernay shale basin with the depth of the reservoir and other geomechanical parameters. The stresses in the Ireton, Upper Duvernay, Lower Duvernay, and Cooking Lake reservoirs also varies from the West to the East shale basins. High-tier logging, core measurements, and field data were used to build a mechanical earth model, which is then input for hydraulic fracture simulations. Whole core images and image logs indicate the Duvernay to be a naturally fractured reservoir. Because pore pressure is a direct input into the interpretation for in situ stresses, we sensitized on seven pore pressure profiles through the Ireton, Upper and Lower Duvernay, and Cooking Lake reservoirs. Typical pumping design currently being implemented in the Upper Duvernay was used to determine hydraulic fracture geometry based on the various in situ stress profiles. Black oil PVT models were built to run numerical reservoir simulation production forecasts to understand the effect of variations in geomechanical properties on well production performance. The effect of the varying hydraulic fracture properties on well spacing was also investigated for the seven pore pressure profiles, by combining the complex hydraulic fracturing and reservoir simulation.
The results clearly indicated the need to better understand, quantify, and constrain the in situ stress profiles variations with changes in pore pressure models. Hydraulic fracture length is greater within the Upper Duvernay when a constant pore pressure is modeled in the Ireton, Duvernay and the Cooking Lake, which leads to an overestimation of production. If a normal pore pressure is modeled in the Ireton with overpressure in the Duvernay, the hydraulic fracture grows into the Ireton and gives a more realistic production forecast. When the modeled pore pressure is gradually ramped up from the Lower Ireton into the Duvernay, slightly greater fracture length is created in the Duvernay but not enough to make a huge difference in forecasted production. These varying results for the modeled hydraulic fracture geometries impact the optimum number of wells per section.
As more wells come on production and the economic viability of the play is proven, operators will drill more wells per section. Thoroughly understanding the variations in geomechanics across the formations above and below the Duvernay is important. This objective of this study was to drive the conversation about the data that need to be collected and tests that should be run to support the optimization of economic development of the play for years to come.
Multistage hydraulically fractured horizontal well completions have come a long way in the last two decades. Much of this advancement can be attributed to the shale gas revolution, from which numerous transformational tools, techniques, and concepts have led to the efficient development of ultralow-permeability resources on a massive scale. Part of this achievement has been through a widespread trial and error approach, with the higher risk/failure tolerance that is a trademark of the statistical nature of the North American unconventional resource business. However, careful consideration must be taken not to blindly apply these techniques in more permeable tight gas formations, which often cover an extensive range of permeability. Inappropriate application can compromise the effectiveness of the hydraulic fracture treatment and impair long-term well productivity.
Khazzan is a tight to low-end conventional gas field in the Sultanate of Oman, with low porosity and permeability in comparison to conventional formations. The target formations comprise extremely hard, highly stressed rocks at high temperature. The development strategy included vertical wells with massive hydraulic fracture treatments and multistage fractured horizontal wells. The former has been largely successful in the higher-permeability areas, and the economic transition from vertical to horizontal well development, based on rock quality, is continuously evolving. Compared to the rapid learning curve achieved through the more than 80 vertical wells drilled to date, fewer horizontal wells have been drilled, and, as a result, the understanding is still relatively immature.
The paper outlines the technical and operational journey experienced in horizontal wells, to prepare the wellbore and ensure a suitable frac/well connection for successful fracturing and well testing. The paper will describe how the intervention tools and practices have varied between the Barik and Amin formations; depending upon rock quality, frac treatment type, drive to maximize operational efficiency and availability of local resources. The differential application of these techniques, that result in measurable under-flush versus in contrast to the typical North American unconventional practice of defined but limited overflush (e.g., pump-down plug-and-perf will be described). Justification for these different approaches in two very different formations will be demonstrated, including supporting evidence of their relative value.
The obstacles that have been faced, overcome and are still ongoing with this campaign highlight the importance of several critical factors: including multi-disciplinary integration and planning, wellbore construction impacts, contractor performance and tool reliability. Although practices for shale and very low permeability sands are well documented, this paper provides a suite of case histories and operational results for horizontal well intervention techniques used in high-pressure and high-temperature sandstones that are in the very specialized transition zone between conventional and unconventional.
Jiang, Li-Wei (PetroChina Zhejiang Oilfield Company) | He, Yong (PetroChina Zhejiang Oilfield Company) | Shu, Dong-Chu (PetroChina Zhejiang Oilfield Company) | Niu, Wei (PetroChina Zhejiang Oilfield Company) | Pan, Feng (Schlumberger) | Wang, Yue (Schlumberger) | Li, Kai-Xuan (Schlumberger) | Zhao, Hai-Peng (Schlumberger) | Tang, Yu (PetroChina Southwest Oil and Gas Company)
Most bedding-parallel fractures in the WuFengLongMaxi Formation, SiChuan basin, are calcite filled and commonly show slickensides, which features characterize bedding-parallel shear fractures. Such fractures can serve as flow channels and storage spaces in gas shale reservoirs. However, little is known about their size and spatial distribution, the relationship of their permeability to the confining stress, and any relationship with porosity. Knowing these relationships may contribute to understanding the role of bedding-parallel shear fractures in shale gas enrichment.
Bedding-parallel shear fractures were measured from core and image logs from the WuFeng-LongMaxi Formation, southern SiChuan basin, supplemented with stress-dependent permeability experimental data and nuclear magnetic resonance (NMR) logs from the same wells. Core and image logs were used to characterize the spatial organization of the fractures. A stress-dependent permeability experiment was proposed to investigate the fracture permeability response to changes in confining stress. The effect of the fractures on porosity was examined in terms of the macroporous component reflected by the NMR T2 relaxation; macropores are more likely to be preserved in gas-rich shale. Study of 27 wells spanning 100 km west-east across the southern SiChuan basin revealed the aperture size of bedding-parallel shear fractures ranges from 1 cm to 50 cm. In most wells, the fractures are much more intense in organic-rich intervals, which have low elastic modulus compared to the overlying nonorganic shale and underlying stiff limestone. The stress-dependent permeability experiment suggests that permeability in samples with the fractures is two to three orders of magnitude larger than in samples without fractures under the same confining stress. Fracture permeability decreases exponentially until the confining stress reaches 25 MPa. NMR analysis indicates that the macroporous component has an inverse relationship with the intensity of bedding-parallel shear fractures.
The thermal maturity of organic-rich mudstones is one of the main parameters to evaluate, when appraising a new area in an unconventional shale play project, to decide on the best field development strategy and to define the landing zones. Conventionally, thermal maturity is derived from optical vitrinite reflectance measurements, but this technique has some limitations in marine sediments with lack of terrestrial material. Other techniques, such as Rock-Eval pyrolysis, are destructive and the results can be biased if oil-based mud is used to drill the well. In this contribution, a fast, easy and non-destructive method known as Raman spectroscopy is proposed to estimate the maturity of mudstone samples from the Argentinian Vaca Muerta formation, collected from a wide range of maturities.
Raman spectroscopic measurements were executed on a variety of Vaca Muerta shale samples. A complete maturity depth profile was acquired for one well over the entire Vaca Muerta organic shale sequence. Additionally, samples from eight further wells, presenting a wide range in the expected maturity, were examined with the Raman technique. Using a correlation between the Raman spectroscopic signal and vitrinite reflectance, established earlier based on a set of reference samples, containing organic-rich mudstones from a variety of paleo-marine sedimentary basins in North America, thermal maturities were derived for the Argentinian shale samples. For certain samples kerogen was extracted and properties of the isolated kerogen were measured. The Raman results were not only compared to standard maturity indicators such as vitrinite reflectance or Rock-Eval pyrolysis, but also with other non-standard techniques like DRIFTS (Diffuse Reflectance Infrared Fourier Transform Spectroscopy) or results derived from the kerogen properties.
This case study in the Vaca Muerta shows a good correlation between the maturity values derived from the Raman measurements and maturities inferred from other methods. The depth profile shows a trend of increasing maturity with depth as expected for such a thick unconventional reservoir.
In contrast to other techniques that require isolation of kerogen, polishing of the sample surfaces, or even crushing of the samples in addition to excessive cleaning, the Raman technique utilized here was applied directly on core chips with minimal sample preparation. This non-destructive technique is fast and easy, while the accuracy is comparable to other techniques like infrared spectroscopy, kerogen skeletal density, or optical vitrinite reflectance measurements. The simplicity and accuracy of the Raman technique can provide critical information about vertical and lateral variability of thermal maturity at basin scale in a short period of time, helping to understand the burial history and its relationship with the variability of hydrocarbon properties.
The objective of this study was to examine the techniques of selecting logging-while-drilling (LWD) tools for geosteering in unconventional reservoirs by examining the workflows and choices from case studies. When planning a horizontal well one of the most important decisions is choosing the measurement that will be used to steer. Which tool to select depends on the measurement contrast between the target formation and the surrounding formations, target thickness and most importantly what are the project objectives.
Judiciously choosing the correct measurement can help maximizing exposure within the target window and reduce trouble time and sidetracks. Steering within unconventional reservoirs is generally done using the simplest measurements possible, the measurements-while-drilling gamma ray (MWD GR). This is due to cost or lack of perceived need for additional measurements, or because GR gives enough information with the large amount of offset data that exists. We looked at several case studies where tools were selected by analyzing the offset for measurement contrast and forward modeling the planned well trajectory across the zone and exiting the top and base of the target window.
One case was a series of wells in the Olmos sand found in the coastal area of south Texas. The target is a higher-porosity layer within the Olmos “C” sand, which is approximately 10 to 12 ft thick with surrounding rock is that is tighter but will produce if fractured. The project objective was to drill wells to maximize exposure in the high-porosity layer, then hydraulically fracture the reservoir. The offset log data was forward modeled, then the best measurement that would achieve project objectives was chosen and the wells drilled.
The offset data was forward modeled and it showed that because of the symmetrical nature of the target window, an azimuthal measurement was needed. Both azimuthal GR or resistivity would work in this environment, but to distinguish between the tighter formation above and the target with a similar resistivity value a different measurement would be needed to have a unique measurement that could distinguish between the higher density rock above the target and lower density rock below the target, and an imaging density tool was selected to steer the well.
The wells were landed in the target zone using a conventional gamma ray (GR), and then geosteered during the lateral using real-time density images from an LWD tool. The images were used to measure formation dips, both within the target and after the trajectory was forced out of the zone by a subseismic fault. The formation dip was determined to plan the sail angle to allow for getting back in zone most efficiently.
Selecting the proper measurement by careful analysis beforehand allowed the wells to be steered successfully, which led to increased production compared to offset horizontals steered without an azimuthal measurement.