Today many exploration, appraisal and development welltest operations are performed in new frontiers. These include extreme environmental conditions and reservoirs bearing complex reservoir fluids, such as heavy oil, or fluids with a high concentration of H2S, CO2, high wax and asphaltenes content, which have rarely been tested in the past. Many failures and operational issues have hindered the interpretability of data, significantly increased the total costs of such well tests or led to severe HSE incidents.
Currently, such operations are often designed and executed on a case-by-case basis, and there are no practical recommendations available that would summarise the well testing experience in such environments to guide the operating companies through the process of efficiently planning welltest operations. Consequently, operations are often planned on a "copy-paste" basis, with potentially disastrous consequences.
This paper describes in detail the challenges associated with safety, flow assurance, safe handling and disposal of produced fluids, and data quality during current welltest operations with complex reservoir fluids or challenging environmental conditions. Complex reservoir fluids, including highly corrosive fluids, introduce unique challenges that need to be addressed at the design stage of the test, each requiring an appropriate design of surface well test spread and DST string, as well as the overall job operation and equipment planning to incorporate "what-if" scenarios. To address these issues, we summarize the best well-testing practices, and for each of the cases outlined illustrate proven welltesting techniques. Examples show that it is nearly impossible to perform the well test and handle complex reservoir fluids at surface using a traditional approach and standard well test equipment. Novel well testing equipment such as new generation welltest separators equipped with Coriolis mass flow meters, new generation burners and others, in combination with recently developed well testing techniques, allowed us to overcome these challenges.
The paper provides practical recommendations, supported by case studies, highlighting the results and lessons learned from successful operations around the worlds in the following well test areas: Heavy oil testing Well test operations in high H2S and CO2 environment Well test operations in reservoir fluids with high wax or Asphaltene content Deepwater welltest operations with a high risk of hydrate formation Well test operations with production of foamy oil Heat management Viscous fluid management Contingency planning
Heavy oil testing
Well test operations in high H2S and CO2 environment
Well test operations in reservoir fluids with high wax or Asphaltene content
Deepwater welltest operations with a high risk of hydrate formation
Well test operations with production of foamy oil
Viscous fluid management
Recipes for success are provided to ensure that safe operation can be performed in the challenging environment while keeping the cost in line with the AFEs.
In the last decade, many gas reservoirs with permeabilities from 0.1 to 10 mD have been developed with horizontal wells with transverse fractures. The potential negativeimpact of convergent flow in the fracture seems to have been forgotten. The widespread use of resin coated proppant (RCP) in offshore wells appears to make this problem worse. Using both case studies and reservoir simulations, we examine why RCP could make the problem of convergent flow worse compared to uncoated proppant.
A number of North Sea horizontal and deviated multi-frac gas wells that used RCP and had a significant mechanical skin are presented. Pressure buildup data confirms the presence of a near-wellbore pressure drop in the fracture. Reservoir simulation with a fine grid reproduces the observed pressure drop, due to convergent flow, using realistic proppant pack permeabilities with gel damage.
The effect of proppant production on the convergent flow skin is shown using production data before and after discrete proppant production events, demonstrating how proppant production has a beneficial effect on removing convergent flow skin. We also compare the performance of a new horizontal multi-frac well to the original discovery well in the same location, where a vertical well was fracture stimulated with uncoated proppant, and had comparable productivity.
If there is a large convergent flow skin in a fracture with uncoated proppant, this usually leads to some proppant production, which could create "infinite conductivity" channels at the perforations. This removes the convergent flow pressure drop. If RCP is used to prevent proppant flowback, such channels cannot form easily and convergent flow acts as a downhole "choke" on production. This "choke" can produce a significant positive skin. In unfavorable cases, a horizontal multi-frac well with 3 or 4 transverse fractures will produce the same as a fully perforated vertical well with a single fracture.
Based on a number of real-world incidents of proppant production during the post-fracture cleanup, we show strong evidence that a small amount of proppant production can result in an increase in well PI and decrease in apparent fracture skin. Convergent flow is the most likely mechanism to explain this. This paper highlights the potential reduction in well productivity due to using resin coated proppant for fracturing in gas wells (0.1 to 10 mD) with limited inflow area (transverse or oblique fractures) where convergent flow pressure loss is significant. We show the potential positive effect of small amounts of proppant production in such cases, forming infinite conductivity channels and removing the convergent flow skin.
AbstractThis paper describes a unique combination of equipment and techniques that enabled an ESP-DST well test on a shallow, horizontal well drilled in a faulted and heterogeneous reservoir with complex fluids, in Arctic conditions.The technical challenges of the performed well test included designing a bespoke ESP-DST string compatible with the shallow reservoir and designing a surface well test spread capable of efficient separation for safe and environmentally friendly disposal, and obtaining accurate flow rate measurements, as well as performing a test with interpretable data given the uncertainty and complexity of the formation, and the complexity of the well itself.The success of the performed well test was the result of an integrated approach to well test design and real-time support provided throughout. This process included the selection of optimum ESP-DST string design for multizone testing in a high angle well including an innovative arrangement of an ESP encapsulated in a POD and installed in the riser. Integration of ESP with the surface well test package was also important and the design of the surface well test package included a Coriolis type of separator and multiphase flow meter for accurate flow rate measurements.During drilling, the contingency plan to mitigate against losses was implemented which had a significant effect on the well testing program. To address this, and to understand if the well objectives could still be achieved, an uncertainty-based well test design and interpretation methodology, taking into account reservoir uncertainties and their interaction with each other, which uses numerical models and a global sensitivity analysis method was applied. This method identifies which uncertain reservoir parameters can be interpreted confidently and indicates the test duration. From the hundreds of numerical simulation cases produced during the design stage of the test, matches were obtained during monitoring to give an indication of the future pressure behavior, which allowed the duration of final build-up to be optimized.The ESP-DST well test was successfully performed on a horizontal well drilled in the Wisting discovery in the Barents Sea. The well was successfully free flow tested giving a maximum achieved flow rate of 5,000 barrels of oil equivalent per day. All the well test objectives were successfully achieved, despite the change to the contingency drilling plan.
Putra, Rieza R. (Pukesmigas Trisakti University) | Larasati, Dian (NEGT Pertamina Upstream Technology Center) | Ardi, Sunarli (NEGT Pertamina Upstream Technology Center) | Fiqih, Fikri Muhammad (Pertamina Hulu Energi) | Ramdani, Hilman (Pertamina Hulu Energi) | Widarto, Djedi (NEGT Pertamina Upstream Technology Center) | Guntoro, Agus (Pukesmigas Trisakti University) | Usman, Alfian (NEGT Pertamina Upstream Technology Center)
Integrated from regional studies, geomechanical test from WCBF outcrop sample, conducted to determine where exactly placement of effective coal cleat accumulation. However, this paper focusly on structural and geomechanical aspect and which deformation phase that causing effective cleat accumulation.
Macroscale approach based on three stopsite of WCBF obtained major of west-east trending face cleat and north-south trending of butt cleat. The major trend of coal cleat respectively correlate with regional west-east shortening deformation phase due to tectonic inversion by Meratus Mountain during pliocene-pleistocene. Number of permeability value based on macroscale technique using outcrop matchsticks and cubes formula run widely in 7-46 darcy interval. Mesoscale approach using FMI analysis shows similar west-east coal cleat in subsurface (Coal Zone A) and strongly correlate with downward coal zone (B and C). Permeability value of mesoscale technique at 7.05 md and 5.2% of porosity based on CT Scan analysis from WCBF outcrop sample (TJ-11). The value of mesoscale permeability shows good negative exponential relationship through subsurface permeability test using IFO Test from 414-616 m of depth with range of permeability 3.3-0.23 md. Microscale measurement using SEM analysis from TJ-09, TJ-10, TJ-11 have values range from 0.6, 18.53, 17.824 md. As tested by mesoscale permeability integrated to IFO Test, each of approximation parameter would be respectively following the mesoscale exponential power law.
Geomechanic test was directly tested to SPL-03 sample from WCBF shows number elastic moduli; Young Modulus at 2652.74 MPa, Bulk Modulus 1163.48, Poisson Ratio 1069.65. Hydrostatic crossplot between depth against pressure (confining pressure from uniaxial test) clearly shows that overburden stress (SV) have no influence to create effective stress-driven cleat prior to deformation (Shmax and Shmin).
Fault Facies gave a brief classification of the area surrounding the fault which accomodate most effective cleat abundance in damage zone of the fault. Using weight factoring correlation between paleogeographic and strain partitioning by observe the geometry changing between bisected σ1 and σ3 trajectories. The most effective types of cleat occurs in distributed conduit and combine conduit barrier fault area with tensional-rotational and contractional-rotational strain region.
Rocks that exhibit multi-modal throat-size distributions cannot be reliably appraised and classified using conventional methods such as Winland R35 (Pittman, 1992) or Amaefule's flow zone indicator (Amaefule et al., 1993). Such popular classification procedures/protocols are tacitly based on the concept that rocks exhibit a single dominant throat-size, and they do not consider neither the multi-modality nature of throats, nor the variation in the amplitude of throat or grain-size distributions. Carbonates and tight-gas sandstones are notorious for their non-unimodal variability of throat sizes. Wide variations of throat sizes are also often observed in rocks which have been subject to extreme diagenesis and recrystallization.
This paper introduces new rock classification methods based on mercury-intrusion capillary pressure (MICP) and grain-size distribution measurements. We use three types of parametric basis functions to reproduce logarithmic throat-size and grain-size distributions derived from MICP data and grain-size distribution measurements. Magnetic resonance data are also invoked to quantify irreducible water saturation. First, a multi-modal Lorentzian distribution function is introduced where the function's free parameters are used to establish correlations between permeability and irreducible water saturation. In cases where grain-size data are available, we show how to estimate irreducible water saturation based on the surface-to-volume ratio of the rock. Results are then compared to a bimodal Gaussian distribution (Xu et al., 2013), and Thomeer hyperbolas (Thomeer, 1960), to assess when each method may or may not be more accurate to model the distribution of throat sizes and the corresponding flow properties. Finally, we introduce a new rock classification method that accounts for all pore and throat-geometry parameters to quantify storage and flow properties of rocks.
In the case of Cotton-Valley group tight-gas sandstones, the new rock classification method reliably identifies outlier permeability measurements and groups rocks with common pore textural properties. We emphasize the importance of assimilating the multi-modality of throat sizes with a Panoma carbonate field example, where a more accurate rock classification is obtained when compared to the flow-zone indicator method. Finally, we examine the case of a clastic offshore field in Trinidad, where additional petrophysical data confirm that the bimodal nature of the grain-size distribution renders a reliable estimation of irreducible water saturation.
The Grove field is located in the Southern North Sea and has been in production since 2007. The Grove A well lies within block 49/10a and was originally planned by Centrica as an infill well, drilled horizontally in the central fault compartment of the Grove field structure. The well targeted the relatively undepleted basal "A" sandstone unit of the Late Carboniferous, Westphalian reservoir, also known as the Barren Red Measures (BRM).
The well objectives were to 1) target the Grove A sand from the G1 "donor" well, 2) establish a suitable completion strategy for field development, 3) assess the performance of a multiple stage (four to five) hydraulically fractured horizontal well, 4) acquire sufficient log data to fully evaluate the reservoir, and 5) acquire reliable permeability and reservoir pressure measurements to assist in reservoir simulation.
The A sand reservoir unit has a porosity of approximately 10% and permeability between 0.05 to 1 md, with a reservoir with true vertical thickness (TVT) of approximately 140 ft at the heel and 40 ft at the toe. The reservoir unit is poorly drained by the other wells, and the Grove infill well is the first horizontal gas well in the field to be stimulated by means of multistage hydraulic proppant fracturing. The hydraulic fracturing treatment used sand plug isolation to separate consecutive fracture stages, and the fracture stimulation operations were performed with the rig in place by means of a converted stimulation vessel. The stimulation treatments successfully used a modified sand plug methodology that employed aggressive breaker schedules and fluid injections rates that were determined to be more efficient than previous treatments based on employing strict "sand plug setting" criteria. The findings are presented, as well as analyses of both prefracturing and fracturing data for the treatments together with results of the well post-completion and hook-up production.
This work should be of interest to offshore operators world-wide performing multiple hydraulic fractures in both horizontal and vertical wells using sand plug isolation technology.
Obtaining accurate and representative well testing information is critical for the proper characterization of a reservoir, with confidence and quality of data being of paramount importance during a well test. Over the last few years, well testing has become real-time enabled, following in the footsteps of drilling, wireline logging and production operations. However, making a better well test is not just about enabling the technology. It is also about ensuring that the right people have access to the right data and that adequate decision-making processes are available. This requires that reservoir engineers are trained in operational aspects, rig crew are able to communicate and implement remotely taken decisions, and the "end-users" of the well test are fully engaged in the real time monitoring, analysis and execution processes.
The real-time well testing approach presented in this paper is the result of the evolution from basic real-time data transmission to a reliable real-time data delivery and analysis infrastructure that has taken place over the last five years. Throughout the 100 real-time well tests completed in the North Sea, the workflows used to process and analyze the data have evolved significantly, enabling the processed information to be leveraged for decision-making and to update test programs. Recently developed downhole tools and components controlled remotely via a wireless acoustic telemetry system, and providing real-time access to downhole pressure data, have enhanced and broadened the applicable workflows and capabilities.
This paper also presents the evolution of remote connectivity systems and the exploitation of their technical capabilities to their full potential so that off-site experts can witness, collaborate and support operations on a 24/7 basis. By these means, the right expertise can be utilized regardless of location. In addition, we present several case studies where real time data delivery, remote monitoring and support were crucial for continuous quality assurance and for successful pressure transient analysis which led to better reservoir characterization. The change in the mindset of management in both operating companies and service suppliers is essential to ensure that the power of real-time enabled well testing is fully leveraged.
Copyright 2014, Society of Petroleum Engineers This paper was prepared for presentation at the SPE Bergen One Day Seminar held in Grieghallen, Bergen, Norway, 2 April 2014. This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of SPE copyright. Abstract Well Testing for reservoir characterisation and production assessment has always been critical, especially in offshore highpressure, high-temperature (HPHT) environments. A limitation of technology available for HPHT environments in conjunction with strict safety and environmental constraints elevate the operational challenges over those associated with non-HPHT well testing.
Copyright 2014, Society of Petroleum Engineers This paper was prepared for presentation at the SPE/EAGE European Unconventional Conference and Exhibition held in Vienna, Austria, 25-27 February 2014. This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of SPE copyright. Abstract There is an increasing hydrocarbon demand from a diminishing resource base in the North Sea. Technological advancements and government support coupled with activities in the UK Continental Shelf are enabling the development of untapped heavy oil resources. Heavy oil appraisal-well testing has always been a primary source of information for reservoir characterization, well deliverability, and evaluation of potential technologies for further application in field development. Until recently, heavy oil well tests have been limited and deemed challenging because of the complexities associated with the nature of the heavy crude and lack of a proven well-test concept with a strong track record.