In a deepwater environment, production fluid conditions have to satisfy complex requirements to flow smoothly to the production facilities on the FPSO. Flow assurance specialists work at turning these constraints into operating guidelines. This allows to close the gap between reservoir conditions, optimized design of the subsea network, topsides processing capabilities and operability requirements.
In the context of Kaombo, offshore Angola (Block 32), the wide range of reservoir conditions and fluids plus the extreme specificities of the subsea network called for an innovative approach with the following objectives: Empower the operator with a visual decision tool for normal and unplanned operations of the subsea system Promote collaboration between production, flow assurance & geoscience teams to reach an efficient decision, and minimize production shortfalls Allow a design robust enough to tackle geosciences uncertainties Optimize subsea design margins
Empower the operator with a visual decision tool for normal and unplanned operations of the subsea system
Promote collaboration between production, flow assurance & geoscience teams to reach an efficient decision, and minimize production shortfalls
Allow a design robust enough to tackle geosciences uncertainties
Optimize subsea design margins
This new approach, the "Visual Operating Envelopes", aims at explicitly and visually defining the operating limitations of the subsea production loops in a multi-parameters environment: A multi-dimensions map, function of the six main parameters (basically liquid and gas-lift flowrates, water and gas contents, reservoirs pressure and temperature) influencing multiphase flow into pipeline is hence created to evaluate the six main operating constraints (thermal and hydraulic turndown rates, wells eruptivity, maximum flowrates) for the full range of Kaombo fields.
This "operating envelope" tool can then define the minimum and maximum recommended flowrates for different operating conditions based on the following safe criteria: Arrival temperature above the Wax Appearance Temperature No hydrates risk during preservation No severe slugging effect Production below the flowline design flowrate Velocity below the erosional velocity
Arrival temperature above the Wax Appearance Temperature
No hydrates risk during preservation
No severe slugging effect
Production below the flowline design flowrate
Velocity below the erosional velocity
In addition, the optimized gas lift flowrate is directly accessible, and the pressure available at every wellhead is compared to the backpressure associated to the operating point to assess the eruptivity of the wells.
By having previously defined an overall operating envelope, it is extremely easy to evaluate quickly the impact of new operating conditions (due to degraded operating conditions, changes in reservoir parameters, modifications in the drilling and wells startup sequence), which makes this new approach very powerful and versatile. It also contributes to the definition of the production forecast during operation phase integrating reservoir depletion and available gas lift rate.
Instead of relying on specific simulations for a limited number of cases, this innovative method defines a new approach where operating parameters are evaluated from the start, and boundaries are clearly identified, thus allowing to build a sound production profile for an extensive range of operating conditions. By doing so, system knowledge is improved, bottleneck conditions are anticipated, operators, flow assurance and geoscience teams are able to tightly collaborate and take smarter decisions together, resulting in more production. Eventually the method applied to a multiphase pipeline is actually transposable to every problem involving multi-dimensional inputs with combined constraints.
Digitalisation will rapidly change the way we work, which will impact the entire workflow from planning and delivering wells to monitoring and controlling wells and reservoirs. We will be introducing digital tools to current human workflows, which should aim at increasing the efficiency and accuracy of plans and of monitoring activities. The current plans will have to change and address that their output may be input for advisory systems for field operating personnel or the machine, which may be highly robotic. Latest developments in automation of rigs, but also wellheads and surface facilities suggest that we may rather plan for machines as seen in industrial CAD/CAM processes. Certain activities, e.g. the production of a well in the context of a reservoir and field may be highly automated and partly even autonomous.
An area of great interest to those researching flowback is the interaction of water and salt inside the shale reservoir. After a well is stimulated, the flowback fluids tend to show a rising concentration of salt that falls back to near zero over time. Most shale producers in North America have given little thought to the flowback stage following hydraulic fracturing. Others have come to realize it represents a valuable opportunity to learn more about their wells. On the far end of the flowback spectrum is a completion process called soakback.
Most shale producers in North America have given little thought to the flowback stage following hydraulic fracturing. Others have come to realize it represents a valuable opportunity to learn more about their wells. A rigorous modeling approach is developed for effective management and inventory analysis of natural-gas storage in underground salt caverns.
The most important mechanical properties of casing and tubing are burst strength, collapse resistance and tensile strength. These properties are necessary to determine the strength of the pipe and to design a casing string. If casing is subjected to internal pressure higher than external, it is said that casing is exposed to burst pressure loading. Burst pressure loading conditions occur during well control operations, casing pressure integrity tests, pumping operations, and production operations. The MIYP of the pipe body is determined by the internal yield pressure formula found in API Bull. The expression can be derived from the Lamé equation for tangential stress by making the thin-wall assumption that D/t 1.
The Bone Spring and Wolfcamp formations of the Delaware Basin consist of mixed sediment gravity flow and suspension sedimentation deposits. These deposits exhibit high levels of heterogeneity both at and below core and log scales. A comprehensive approach integrating core and sub-core (nanoscale) data from two key wells and well logs within central Ward County was used to characterize small scale changes in lithology, rock properties, and reservoir quality. With this approach, a total of nine facies were identified; three siliceous mudstones [1, 2, 3], three siltstones [4, 5, 6], and three carbonates [7, 8, 9]. Each is comprised of different grain size distributions, textures, mineralogies, and pore types. Facies are not unique to an individual facies associations and cannot be predicted laterally in this study. Core-based measurements of source and reservoir properties were used along with qualitative observations from thin sections and high-resolution SEM images to identify facies as primary reservoir facies, secondary reservoir facies, and non-reservoir facies. Properties concerning source, reservoir, and mechanical quality were evaluated with respect to each facies and within each stratigraphic unit; 3rd Bone Spring, Wolfcamp A, Wolfcamp B, and Wolfcamp C.
Within the study area, 210 sq. miles in central Ward County along the eastern flank of the Delaware Basin, the Bone Spring and Wolfcamp formations are in the early mature oil window (0.69% – 0.88%Ro) and consist of an intercalation of siliceous mudstones [1, 2, 3], siltstones [4, 5, 6], and carbonates [7, 8, 9]. The four reservoir facies [1, 2, 4, 5] identified are organic rich with average wt.% total organic carbon (TOC) as follows; argillaceous siliceous mudstone  (3.1 wt.%, n=21), calcareous siliceous mudstone  (3.0 wt.%, n=15), argillaceous siliceous siltstone  (2.0 wt.%, n=7), and calcareous siliceous siltstone  (2.3 wt.%, n=7). Primary reservoir facies [1, 2] are richer in type II kerogen than the mineralogically comparable but coarser-grained secondary reservoir facies [4, 5], which contain more detrital grains and type III kerogen. Lower organic content in secondary reservoir facies [4, 5] is related to the dilution of organic matter via an extrabasinal influx of detrital grains and possible consumption by benthic fauna in oxygenated conditions. Degree of anoxia, bioturbation, and silica origin all have significant implications to reservoir quality as seen in the mineralogically similar non-reservoir biogenic siliceous mudstone facies  and the primary reservoir argillaceous siliceous mudstone facies . The former contains the least amount of detrital silica and organic matter of all facies observed. Early diagenesis of radiolaria and siliceous spicules source the microcrystalline authigenic quartz that was observed to occlude pore space in this non-reservoir facies . Despite the poor source potential and reservoir quality of this facies , the high amounts of microcrystalline authigenic quartz are beneficial to reservoir geomechanics. Implications to reservoir quality identified in this work have limited utility outside of the study area away from the flank of the basin, where bioturbation, degree of anoxia, and prevalence of extrabasinal facies differ. GRI saturations, MICP measurements, NMR (T2LM) data, and core-based TOC measurements indicate siliceous calcareous siltstone  as a facies potentially making up water-bearing carrier beds. Carbonate-rich facies [6, 7, 8, 9] were sampled least from core and more work must be done to better evaluate reservoir potential of these facies.
Core-based measurements of composition and reservoir quality indicate that porosity and permeability trend positively with clay, pyrite, and TOC, and negatively with carbonate. This relationship with porosity is most evident and statistically significant in the fine-grained facies [1, 2, 3, 4, 5], where silica is always the primary constituent. Relatively high clay content, upwards of 34 wt. %, in this study is not observed to negatively impact mechanical behavior. Porosity and TOC are highest in the Wolfcamp A and lowest in the lower Wolfcamp B subdivision, a trend observed beyond core control within the two key wells and on logs throughout the study area. This is largely a function of facies distribution. Based on stratigraphic architecture, facies distribution, and lack of thick non-reservoir carbonate barriers, the Wolfcamp A and upper Wolfcamp B may be considered one flow unit. This may allow well spacing and number of wells to be strategically optimized per drilling unit. Development strategies with respect to well spacing and well planning, may be better constrained with an understanding of each facies’ source potential, reservoir and mechanical quality, and distribution within each stratigraphic interval. Findings and interpretations from this research contribute to larger scale efforts being made to: 1) understand the role of diagenesis in unconventional reservoir quality; 2) recognize implications of depositional processes in unconventional reservoirs; and 3) image unconventional facies at the nano, micro, and macro scales.
Wellbore instability is caused by the radical change in the mechanical strength as well as chemical and physical alterations when exposed to drilling fluids. A set of unexpected events associated with wellbore instability in shales account for more than 10% of drilling cost, which is estimated to one billion dollars per annum. Understanding shale-drilling fluid interaction plays a key role in minimizing drilling problems in unconventional resources. The need for efficient inhibitive drilling fluid system for drilling operations in unconventional resources is growing. This study analyzes different drilling fluid systems and their compatibility in unconventional drilling to improve wellbore stability.
A set of inhibitive drilling muds including cesium formate, potassium formate, and diesel-based mud were tested on shale samples with drilling concerns due to high-clay content. An innovative high-pressure high temperature (HPHT) drilling simulator set-up was used to test the mud systems. The results from the test provides reliable data that will be used to capture more effective drilling fluid systems for treating reactive shales and optimizing unconventional drilling.
This paper describes the use of an innovative drilling simulator for testing inhibitive mud systems for reactive shale. The effectiveness of inhibitive muds in high-clay shale was investigated. Their impact on a combination of problems, such high torque and drag, high friction factor, and lubricity was also assessed. Finally, the paper evaluates the sealing ability of some designed lost circulation material (LCM) muds in a high pressure high temperature environment.
Zhang, Miao (The Pennsylvania State University) | Chakraborty, Nirjhor (The Pennsylvania State University) | Karpyn, Zuleima (The Pennsylvania State University) | Emami-Meybodi, Hamid (The Pennsylvania State University) | Ayala, Luis (The Pennsylvania State University)
Nano-scale pores and a dual storage mechanism shared between free and adsorbed gas make the transport behavior in shale gas reservoirs very different from conventional macropore reservoirs. This work explores a straightforward model for the gas transport behavior in shale nanopores, which couples sorption, diffusion, and sorbed-phase surface diffusion phenomena. The model combines two governing equations for free and sorbed gas phase transport processes in nanopores, respectively: a diffusion-based equation for free gas phase transport, and a surface-diffusion equation for the sorbed phase. Mass transfer between the two phases is quantified by kinetic models of sorption. The two governing equations are solved simultaneously using finite element methods (FEM). Model performance is successfully validated by closely matching density propagation profiles of a gas transport experiment obtained by quantitative X-ray computerized tomography (CT) imaging for a Marcellus shale sample. Transport-related parameters estimated from history matching are shown to be consistent with literature data.