Large Deformation Finite Element (LDFE) modelling is conducted to study the bearing capacity of large offshore foundations in limited clay depth. Complementary visualising centrifuge experiments are reported in clay with interbedded sand, correlating with the numerical study. The current squeezing methodology neglects the conical underpart of the spudcan and any possible deformation of the underlying layers and hence does not predict the measured resistance well. An alternate approach overcoming the limitations of the squeezing theory is presented and verified.
Offshore jackup drilling rigs are often supported by a quasicircular or sometimes polygonal foundation with a conical underpart commonly referred to as a spudcan. The jackup generally operates in shallow-to-medium water depth (up to ~150 m). Seabed stratigraphies in medium water depths can be layered, consisting of several alternate layers of sand and clay (Baglioni et al., 1982; Kostelnik et al., 2007; Dutt and Ingram, 1984). Limited knowledge is currently available for foundation installation in more than two-layer soil stratigraphies. This could be due to the inherent difficulties in physically modelling more than two-layer stratigraphies directly in the geotechnical centrifuge due to possible boundary effects (Ullah et al., 2014; Ullah et al., 2016). Some centrifuge tests mimicking several offshore soil deposits were recently reported in Hossain (2014) for soil stratigraphies up to six layers.
In the absence of detailed analytical methods, solutions developed initially for two-layer stratigraphies are recommended for more general multi-layer stratigraphies (ISO, 2012). This extended application requires additional assumptions that are often not realistic and require further investigation. The International Organization of Standardization (ISO) guidelines suggest that the bearing capacity calculation for soft clay over a strong soil layer (such as sand or stiff clay) should proceed first by calculating the soil resistance from the available single-layer solutions, such as those of Skempton (1951) or Houlsby and Martin (2003), until the depth of transition (dt) is reached. (See Fig. 1 where ID is the relative density and φcv is the constant volume friction angle.) dt refers to the depth measured from the top of the sand layer to the transitional point on the load-penetration curve where the transition from a near linear uniform clay-type response occurs.
In this study, a gas/liquid flow has been numerically investigated in a rotary gas separator (RGS) to improve the performance of the RGS. One-phase flow and then two-phase flow were analyzed in an inducer, which is the main component of the RGS. A parametric study showed that reduced blade thickness and a higher number of blades increased the inducer’s head. However, an inducer with two blades generated greater head. Higher inlet-flow temperature (by inlet preheating) improved operation conditions, especially in lower flows. In addition, smaller bubble sizes led to a lower head. Alternately, the changes are not significant, and results are close and similar in smaller sizes. In the next step, the performance of the designed RGS was analyzed by computational fluid dynamics (CFD) and validated with available experimental data. Then, the effect of the quantity of the gas-output ports on the RGS’s efficiency was studied. As a result, the system with four ports was suggested as optimal. Moreover, results showed that increasing the length of the separator zone leads to increasing the efficiency until reaching an optimal length equal to the length of the inducer zone. Finally, the effect of the blade number was studied for various rated points.
This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 185053, “Building Type Wells for Unconventional Resource Plays,” by P. Miller, N. Frechette, and K.D. Kellett, Repsol, prepared for the 2017 SPE Canada Unconventional Resources Conference, Calgary, 15–16 February. The paper has not been peer reviewed.
Although the application of statistical techniques to type wells is gaining acceptance, it is often unclear to evaluators how these techniques can be applied to capture accurately the full range of uncertainty in the average single-well estimated ultimate recovery (EUR) for a geologic subset. The objective of the complete paper is to present an integrated work flow that can be used to build P90, mean, and P10 type wells, which represent the range of potential outcomes for the geologic subset in an unconventional resource play.
A common challenge that accompanies new technologies dedicated to the discovery of unconventional resources is how to forecast production and quantify EUR. Early in the life of a resource play, it can be difficult to build type wells because of limited production history and a small well count.
Traditional methods would use an analogous-field well model or decline methods to predict future production. Because of unconventionals being a relatively recent development, no late-life fields exist that can be used as direct analogs to understand mid- to late-time horizontal-well behavior in tight unconventional formations. For plays in the early stages of development, because of the relatively small well count and difficulty with a direct analog, the early-time well behavior is also not easily predicted with confidence. There is thus a high degree of uncertainty in both the shape and the magnitude of the type-well profile. Consequently, it is becoming more common for management to ask for an expected type well with a range to capture uncertainty, rather than a single deterministic estimate. The work flow in this paper applies such methods.
Acknowledging Uncertainty. For unconventional resource plays, the two basic sources of uncertainty are the drilling-and-completion (D&C) design and the geological properties that characterize the reservoir. Ideally, one would select a statistically significant number of wells with identical (or nearly identical) geological properties, completions, lateral length, and drilling azimuth to construct type wells. However, this scenario is often far from reality.
One solution is to wait until enough wells exist with nearly identical D&C designs and geological properties before proceeding with type-well construction. Obviously, this solution is not practical if management needs to rank assets in the portfolio and justify capital allocation for development of some assets but not others. Therefore, alternative solutions to deal with varying D&C designs and geological properties are to normalize production data for D&C design and to define geologic subsets for areas with similar geological properties.
Manchanda, Ripudaman (University of Texas at Austin) | Bryant, Eric C. (University of Texas at Austin) | Bhardwaj, Prateek (University of Texas at Austin) | Cardiff, Philip (University College Dublin) | Sharma, Mukul M. (University of Texas at Austin)
Increasing the efficiency of completions in horizontal wells is an important concern in the oil and gas industry. To decrease the number of fracturing stages per well, it is common practice to use multiple clusters per stage. This is done with the hope that most of the clusters in the stage will be effectively stimulated. Diagnostic evidence, however, suggests that in many cases, only one or two out of four or five clusters in a stage are effectively stimulated.
In this paper, strategies to maximize the number of effectively stimulated perforation clusters are discussed. A fully 3D poroelastic model that simulates the propagation of nonplanar fractures in heterogeneous media is developed and used to model the propagation of multiple competing fractures. A parametric study is first conducted to demonstrate how important fracture-design variables, such as limited-entry perforations and cluster spacing, and formation parameters, such as permeability and lateral and vertical heterogeneity, affect the growth of competing fractures. The effect of stress shadowing caused by both mechanical and poroelastic effects is accounted for.
3D numerical simulations have been performed to show the effect of some operational and reservoir parameters on simultaneous-competitive-fracture propagation. It was found that an increase in stage spacing decreases the stress interference between propagating fractures and increases the number of propagating fractures in a stage. It was also found that an increase in reservoir permeability can decrease the stress interference between propagating fractures because of poroelastic-stress changes. A modest (approximately 25%) variability in reservoir mechanical properties along the wellbore is shown to be enough to alter the number of fractures created in a hydraulic-fracturing stage and mask the effects of stress shadowing. Interstage fracture simulations show post-shut-in fracture extension induced by stress interference from adjacent propagating fractures. The effect of poroelasticity is highlighted for infill-well-fracture design, and preferential fracture propagation toward depleted regions is clearly observed in multiwell-pad-fracture simulations.
The results in this paper attempt to provide practitioners with a better understanding of multicluster-fracturing dynamics. On the basis of these findings, recommendations are made on how best to design fracture treatments that will lead to the successful placement of fluid and proppant in a single fracture, and result in a set of fractures that are competing for growth. The ability to successfully stimulate all perforation clusters is shown to be a function of key fracture-design parameters.
The Gas Research Institute (GRI) conducted pioneering work on measuring shale petrophysical properties in the 1990s, however, despite growing interest in shales, there are still no set standards with respect to obtaining core petrophysical measurements due to the inherent complexity of shales. Core cleaning is one aspect of this problem.
The objective of this study is to shed some light on the shale core-cleaning conundrum. The study shows the cleaning impact of different solvents on samples from different maturity windows and having different in-situ fluids. It also compares the cleaning efficiency between plug and powdered samples. Different cleaning apparatus, such as the high-pressure extractor (HPE) and the Soxhlet extractor, are also compared.
Different measurements, such as source-rock analysis (S1 and S2 values); gas chromatography-mass spectrometry (GC-MS) extraction analysis; Brunauer-Emmett-Teller (BET) surface area and pore-size distribution help to understand the dynamics of core cleaning. This study was carried out on samples from the Wolfcamp and Eagle Ford formations.
Cleaning has a major impact on various petrophysical properties like porosity (increases up to 50%), S1 (decreases up to 90%) and surface area (increases by 450%). This study showed that cleaning time is a function of maturity and sample state. Samples in the oil-maturity window are much more difficult to clean compared to the samples in the gas-maturity window. Similarly, plug samples are more difficult to clean compared to the crushed samples. Our study shows that toluene, dichloromethane (DCM) and chloroform have similar cleaning efficiencies but n-heptane is less efficient.
Coring is an integral part of any exploration program. The planning for a coring program, coring fluids and corehandling procedures at the wellsite are all very important for preserving the core and getting accurate measurements in the laboratory.
This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 27806, “A More-Holistic Approach to Oilfield Technology Development,” by M. Sequeira, OTM Consulting; H. Elshahawi, Shell; and L. Ormerod, Ormerod Consulting, prepared for the 2017 Offshore Technology Conference, Houston, 1–4 May. The paper has not been peer reviewed. Copyright 2017 Offshore Technology Conference. Reproduced by permission.
The complete paper takes a holistic view of technology maturation that addresses both technical and nontechnical risks. The definition of success is expanded to include the establishment of successful, commercially viable, and sustainable solutions that meet end-user needs and requirements.
The Case for Change
Across the industry, companies have seen tremendous drops in revenue and profits along with returns falling well below the cost of capital. The survivors become much more focused on capital-expenditure reductions, with investments almost entirely driven by near-term free cash-flow generation. The effect on innovation within the industry has been dramatic, yet technological innovation is needed now more than ever.
This situation, while difficult, does offer opportunities. The huge reduction in overall investment and resources will lead to an accelerating production decline in an aging production base and increases the likelihood of significant supply deficits that can only be reversed by a broad-based increase in global exploration and production spend.
Defining the Problem
Historically, the industry has lagged behind high-tech industries in terms of research and development (R&D) expenditure relative to revenues, pace of technology maturation (greater than 10 years from discovery to deployment), and the lower fraction of new technologies reaching commerciality. With the billions of dollars of R&D investments stuck at the end of funnels and awaiting deployment years after their initial development, finding a better way of managing technology maturation is essential. Several issues must be considered:
Understanding and prioritizing water management is key for exploration-and-production operators, not only in terms of reducing overall cost and capital expenditures but also as a means of mitigating operational risk, complying with changing regulatory requirements, and addressing environmental concerns. Water-management decisions within shale oil and gas production fall into three primary categories: water acquisition, water usage within hydraulic-fracturing operations, and the disposal of produced and flowback waters from drilling and production. Shale-fracturing flowback refers to the portion of injected hydraulic-fracturing fluids that returns to the surface before and during initial production. The large quantities of flowback and formation water generated during the fracturing process must be treated before recycling, beneficial reuse, or disposal. Typically, 10–20% returns within 7–14 days, with a rapid decline in quality and quantity. Shale produced water typically refers to water produced during the production phase of the shale wells in the longer term and has significantly lower flow rates and more-consistent quality than flowback water. The characteristics of produced and flowback water vary, but both types of water must be treated properly and disposed of correctly or recycled.
Numerous technologies are available today to enable complete or tailored removal of ionic, organic, and particulate contaminants from source waters for injection or produced waters for discharge.
From fine-particle filtration to remove suspended solids and selective-ion exchange for boron removal to polymeric adsorbents for organic-compound removal, numerous water-management solutions are available to ensure that flowback water and produced water are treated properly for recycling, reuse, or disposal.
The papers featured in this month deal with water management in south Argentina, a salt-tolerant friction reducer, and a novel water-shutoff system for carbonates. I hope you enjoy reading the selected papers.
Recommended additional reading at OnePetro: www.onepetro.org.
IPTC 18936 Integrated-Water-Management Challenges by H. Al-Shammari, Kuwait Oil Company, et al.
SPE 183340 Innovative Approach To Treat Produced Water for Reuse in Saudi Aramco Reservoirs Pressure Maintenance by Mohamed Ahmed Soliman, Saudi Aramco, et al.
SPE 183743 Maintaining Injectivity of Disposal Wells: From Water Quality to Formation Permeability by Ali A. Al-Taq, Saudi Aramco, et al.
SPE 184520 On-Demand Water Control: Molecular Host/Guest Interaction for In-Situ Modification of Formation-Fluid Permeability by Antonio Recio III, Halliburton, et al.
This article, written by Special Publications Editor Adam Wilson, contains highlights of paper IPTC 18836, “How To Design a BHA Rotary-Speed Sweet Spot,” by Jeffrey R. Bailey, SPE, and Andrius Minkevicius, SPE, ExxonMobil; Alexander Bolzan and Victoria R. Wilkins, Hibernia Management and Development; and Joshua S. Pokluda, Esso Exploration and Production Nigeria, prepared for the 2016 International Petroleum Technology Conference, Bangkok, Thailand, 14–16 November. The paper has not been peer reviewed. Copyright 2016 International Petroleum Technology Conference. Reproduced by permission.
Correct placement of the rotary-speed sweet spot of a bottomhole assembly (BHA) provides multiple benefits toward achieving the ultimate goal of drilling to section total depth in a single trip. The process of BHA redesign and tuning for the desired operating parameters provides greater control over the drilling process. Vibration minimization through proper design and operation of the BHA facilitates drilling objectives that include reaching section depth in fewer trips and providing acceptable borehole quality to run casing to depth.
A musician understands the basic principle of a stringed instrument: The frequency of the note made by the instrument varies with the length of the string span. Other parameters play a role, including the string properties and tension. However, once the instrument is tuned and the concert has begun, the musical notes are played principally by changing the length of the vibrating string.
As the finger position is changed on the fingerboard, the pitch of the note changes. Although this is a basic concept to a musician, it is not common today in the oil and gas industry for engineers to apply this concept to BHA design selection.
A BHA is a beam that may be rep-resented by a fourth-order differential equation. Model calculations proceed by subdividing the BHA into elements comprising short sections of pipe in a lumped-parameter model. A 2D model uses a state vector at each mass node comprising the lateral displacement in a plane, tilt angle relative to the center-line, bending moment, and beam shear load. In the lateral bending flex mode, a dynamic side force is applied at the bit at integral multiples of the rotary speed. In the rotary twirl mode, offset mass elements are used to investigate the stability of the BHA to eccentric mass and centrifugal forces.
The dynamic response is considered to be a perturbation from the static solution. The bending strain energy is related to the square of the bending moment in the beam, and calculating the length-averaged BHA bending energy provides a BHA bending-strain-energy vibration index.
Lower values of vibration indices are sought because the dynamic response to a reference input is then minimized (i.e., lower vibrations are then predicted by the model). All such modeled designs are perturbed by identical inputs, and the model results may then be compared on an apples-to-apples basis.
O'Reilly, Daniel I. (Chevron Australia and University of Adelaide) | Hopcroft, Brad S. (Chevron Australia) | Nelligan, Kate A. (Chevron Australia) | Ng, Guan K. (Chevron Australia) | Goff, Bree H. (Chevron Australia) | Haghighi, Manouchehr (University of Adelaide)
Barrow Island (BWI), 56 km from the coast of Western Australia (WA), is home to several mature reservoirs that have produced oil since 1965. The main reservoir is the Windalia Sandstone, and it has been waterflooded since 1967, whereas all the other reservoirs are under primary depletion. Because of the maturity of the asset, it is economically critical to continue to maximize oil-production rates from the 430 online, artificially lifted wells. It is not an easy task to rank well-stimulation opportunities and streamline their execution. To this end, the BWI Subsurface Team applied the Lean Sigma processes to identify opportunities, increase efficiency, and reduce waste relating to well stimulation and well-performance improvement.
The Lean Sigma methodology is a combination of Lean Production and Six Sigma, which are methods used to minimize waste and reduce variability, respectively. The methods are used globally in many industries, especially those involved in manufacturing. In this asset, we applied the processes specifically to well-performance improvement through stimulation and other means. The team broadly focused on categorizing opportunities in both production and injection wells and ranking them—specifically, descaling wells, matrix acidizing, sucker-rod optimization, reperforating, and proactive workovers. The process for performing each type of job was mapped, and bottlenecks in each process were isolated.
Upon entering the “control” phase, several opportunities had been identified and put in place. Substantial improvements were made to the procurement, logistics, and storage of hydrochloric acid (HCl) and associated additives, enabling quicker execution of stimulation work. A new program was also developed to stimulate wells that had recently failed and were already awaiting workover (AWO), which reduced costs. A database containing the stimulation opportunities available at each individual well assisted with this process. The project resulted in the stimulation of several wells in the asset, with sizable oil-rate increases in each.
This case study will extend the information available within the oil-industry literature regarding the application of Lean Sigma to producing assets. It will assist other operators when evaluating well-stimulation opportunities in their fields. Technical information will be shared regarding feasibility studies (laboratory-compatibility work and well-transient-testing results) for acid stimulation and steps that can be taken to streamline the execution of such work. Some insights will also be shared regarding the most-efficient manner to plan rig work regarding stimulation workovers.
Ojha, Shiv Prakash (University of Oklahoma) | Misra, Siddharth (University of Oklahoma) | Tinni, Ali (University of Oklahoma) | Sondergeld, Carl H (University of Oklahoma) | Rai, Chandra (University of Oklahoma)
Pore-network characteristics, such as pore-size distribution (PSD), pore connectivity, and pore complexity, along with irreducible saturations in shales, are important petrophysical parameters for accurate estimation of absolute and relative permeability curves of various phases. We apply a method for estimation of these petrophysical parameters in shales by processing the low-pressure-nitrogen-AD measurements. The method uses effective-medium theory, percolation theory, and CPA to quantify the transport properties of shales. The method has been applied to 35 samples of Eagle Ford and Wolfcamp Shales with different composition and from different maturity windows. Further, samples from the gas and oil windows of Eagle Ford Shale Formation were low-temperature plasma ashed to study the effect of the removal of organic matter on pore-network characteristics and irreducible saturations.
The estimated PSDs of condensate-window samples from Wolfcamp samples are significantly different from those of Eagle Ford samples. Our interpretation methodology indicates that the Eagle Ford samples exhibit better long-range pore connectivity and lower pore complexity compared with Wolfcamp samples. Consequently, Eagle Ford samples from oil and gas windows suggests better flow capacity compared with Wolfcamp samples from the condensate window. Moreover, the pore-network characteristics of kerogen from gas-window samples are significantly different from those of oil window samples. The estimated irreducible saturations for the samples collected from 100-ft interval in Eagle Ford gas window, 30-ft interval in Eagle Ford oil window, and the 60-ft interval in the Wolfcamp condensate window of shale formations exhibit minimal variation with depth. The samples exhibit large variations in organic content, pore connectivity, range of connected-pore network, and pore complexity that do not affect the irreducible-saturation estimates.