The orientation of hydraulic fractures controls the productivity from hydrocarbon reservoirs. Productivity from low permeability formations is greatly improved having multiple fractures oriented transversely rather than longitudinally, relative to a horizontal wellbore. Analytical approximations from the literature for the longitudinal and transverse fracturing stresses are modified to incorporate pore pressure effects and then used to develop a criterion for the orientation of fractures initiating from perforated wells. The validity of this criterion is assessed numerically and is found to overestimate transverse fracture initiation, which occurs under a narrow range of conditions; when the formation tensile strength is below a critical value and the breakdown pressure within a "window."
In horizontal wells, it is easier to achieve longitudinal fracture initiation, as transverse fracture initiation only occurs over a narrow wellbore pressure-at-breakdown window, while longitudinal fracture initiation occurs at comparatively higher wellbore pressures. The numerical study shows that in contradiction with existing analytical approximations, the tangential stress which induces transverse fracture initiation, is a stronger function of wellbore pressure just as the stress inducing longitudinal fracture initiation is. This reduces the breakdown pressure window for transverse fracture initiation compared to what the derived analytical approximations predict. Furthermore, this creates an additional constraint for transverse fracture initiation; the critical tensile strength value, which determines the maximum tensile strength for which transverse fracture initiation is possible for a given stress state.
The range of the
Africa (Sub-Sahara) Eni finished a production test on its Minsala Marine 1 NFW well, located in Marine XII block, 35 km offshore The Republic of the Congo. During the test, the well delivered natural flow in excess of 5,000 B/D of 41 API crude and 14 MMcf/D of natural gas from a 37-m opened section of the discovery's 420-m column. Eni (65%) is operator, with state-owned partner SNPC (25%), and New Age (African Global Energy) Limited (10%). Asia Pacific CNOOC started natural gas production from the Panyu 34-1/35-1/35-2 project at the Pearl River Mouth basin in the South China Sea. Main production facilities for the three gas fields include one comprehensive platform, two sets of underwater production systems, and 13 producing wells. Two wells are producing a total of 21 MMcf/D of gas. The project is expected to reach peak production of 150 MMcf/D.
Africa (Sub-Sahara) Aminex Petroleum Egypt (APE), a subsidiary of UK-based Aminex, discovered oil at its South Malak-2 (SM2) well on the West Esh el Mellaha-2 concession in Egypt. Tests showed flow rates of approximately 430 B/D of 40 API gravity crude oil. Based on the findings at SM2, a full field development program will be presented to the Egyptian authorities and the joint venture partners before commercial development. APE is the operator of the license with partner Groundstar Resources. Foxtrot International discovered oil and gas at its Marlin North-1 well in Block CI-27, offshore Cote d'Ivoire. A 22-m perforated section of a gas-bearing column in a Turonian interval flowed at a stabilized rate of 25 MMcf/D of gas and 150 B/D of condensate through a 46/64-in.
Africa (Sub-Sahara) Bowleven has started drilling operations at the Moambe exploration well on the Bomono permit in Cameroon. Moambe is the second well in a two-well program, approximately 2 km east of the first well, Zingana. It targets a previously undrilled Paleocene Tertiary three-way dip fault block containing multiple sands and will be drilled to an estimated 1620 m in measured depth. Both wells will be logged. Bowleven is the operator and holds 100% interest. Asia Pacific Murphy Oil discovered gas at its Permai exploration well in deepwater Block H in the South China Sea offshore Malaysia. The find is Murphy's eighth consecutive success in the area around the Rotan floating liquefied natural gas project, which is planned to begin its first production in 2018.
Relative permeability and capillary pressure defines relative permeabilities as dimensionless functions of saturation with values generally ranging between 0 and 1. Relative permeability is important for estimating the flow of reservoir fluids. The semilog scale of Figure 1 is convenient for reading the relative permeabilities less than 0.05. Although the curves are labeled "gas" and "oil" in these figures, the phase identity of a curve can be deduced without the labels. For example, the relative permeability that increases in the direction of increasing oil saturation must be the oil relative permeability.
Water is the wetting phase. Figure 1.5 – Primary drainage, imbibition, and secondary drainage for an oil/water system in which the oil and water wet the solid surface equally. Figure 1.6 – Primary drainage and imbibition for unconsolidated dolomite powder (the lines merely connect the data). These authors wrote capillary pressure as the negative of Eq. 4 because oil was the wetting phase for most of the tests. The legend gives contact angles measured through the water phase (in degrees). Leverett and coworkers, based on the evaluation of gas/water capillary pressure data for drainage and imbibition in unconsolidated sands, proposed the following definition: ....................(15.6) The function j(Sw), defined in Eq. 15.6, is known to many as the "Leverett j-function." The j-function is obtained from experimental data by plotting against Sw. The combination is often considered an estimate of the mean hydraulic radius of pore throats.
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.
Analytically-derived criteria are presented for the orientation of fracture initiation from horizontal wellbores drilled in porous-permeable (poroelastic) media. This involves drilling-induced tensile fractures (DITFs) from non-perforated wellbores and completion-induced hydraulic fractures (CIHFs) from perforated wellbores with cylindrical perforation geometry. The criteria are developed considering the tangential stresses on two points (extremes) around the base of the perforation; one for the initiation of longitudinal fractures and another for the initiation of transverse fractures, with respect to the wellbore. In-situ stress state, wellbore pressure, and the formation's mechanical and poroelastic properties are independent variables that are shown to control the orientation of the initiated hydraulic fractures; the dependent variable.
The DITF orientation can be used to constrain the magnitude of the maximum horizontal stress; the most difficult aspect of the in-situ stress tensor to constrain. Transverse CIHF initiation only occurs over a narrow wellbore pressure-at-breakdown window, while longitudinal initiation occurs at comparatively higher wellbore pressures. However, transverse CIHF initiation occurs more frequently than transverse DITFs, because the presence of perforations aids transverse fracture initiation. The region of the in-situ stress states where transverse initiation is promoted is shown in dimensionless plots for perforated and non-perforated wellbores. Fracture initiation criteria for specific cases presented can be used to predict the orientation of fracture initiation in oilfield operations.
The orientation of CIHFs controls the productivity of hydrocarbon reservoirs. Productivity from low permeability formations is greatly improved having multiple fractures oriented transversely rather than longitudinally, relative to a horizontal wellbore. Fracture initiation often follows a plane different to the final fracture propagation plane. Stress re-orientation in the near-wellbore region may promote fracture initiation of different orientation than the orientation dictated by the far-field stresses. The range of in-situ stress states in which transverse fracture initiation is promoted increases as Biot's poroelastic coefficient,
In complex situations production optimisation often differs from plan to reality. Ideally a set of known factors are used to determine the optimal course of action for a production well. However, in reality many factors remain unknown and of those that are, many are only known within a range of uncertainty. Uncertainty is persistent; whether in the form of failed instrumentation, erroneous metering or production reconciliation to multiple reservoirs in commingled completions. Further, well optimisation is always governed by economics and operational constraints. Such constraints limit well surveillance activities and compound uncertainty. These challenges united when a large bore deviated depletion drive gas well on a small unmanned offshore platform in the Otway Basin began to exhibit unexpected production decline.
The large bore gas well with commingled reservoir completions was diagnosed as exhibiting liquid loading behavior. The intervention objective was to isolate the probable formation water source and restore water free gas production. A production log was required to confirm water was present and identify the source from three groups of completed intervals, each separated from one another using packers and mechanical sliding side doors. After risk assessments conducted during the intervention an active decision was taken to abort the work and not isolate the water source in favour of continuing cycled production to maximise gas recovery. Introducing an unknown, production logging identified that one of the three completed reservoir intervals was isolated by a closed sliding side door, previously believed to be open, presenting an incremental production opportunity.
A follow-up intervention retained an objective of isolating the water source, with the additional objective of accessing the isolated reservoir interval. Detailed planning and uncertainty analysis was conducted ahead of the campaign with a key risk being the range of pressure possibly present within this target interval and the resultant wellbore cross-flow immediately after accessing it. Whilst the second intervention experienced mechanical failure, the ensuing pragmatic decisions that were taken "on the fly" ultimately resulted in a successful production outcome. The water source was isolated and incremental rate and reserves were achieved through perforation of blast joints opposite the target interval.
This paper presents the workflows, tools & interventions used to diagnose production decline and optimise production from this challenging well. It is a case study in production surveillance utilising limited data, decision tree analysis and contingency planning for interventions performed with significant operational limitations. It includes the use of slickline production logging, tubing plugs, and electric wireline perforating in a strong cross-flow wellbore environment. This paper will be of interest to operators of unmanned platforms in hostile environments, commingled completions or wells with compromised production data. By integrating the learnings presented, engineers will get a head start when tackling similar uncertainties with their own challenging production optimisation activities.
Summary In the past decades, many exploration wells have drilled into igneous rocks by accident because of their similar seismic expression to the common intended targets such as porous carbonate mounds, sheet sands or deepwater sand-prone sinuous channels. In cases where sedimentary features such as channels or fans cannot be clearly delineated, the interpretation may be driven primarily by bright spot anomalies, and a poor understanding of the wavelet polarity may compound this problem. While many wells that are drilled into igneous rocks were based on interpretation of 2D seismic data, misinterpretation still occurs today using high quality 3D seismic data. We propose an in-context interpretation workflow in which the interpreter looks for key clues or parameters above, below and around the target of interest to confirm the interpretation. Introduction Using modern 3D seismic surveys, significant work has been achieved over the past two decades in accurately imaging the geometry of igneous bodies (Hansen and Cartwright 2006; Holford et al., 2012; Jackson et al., 2013; Magee et al., 2014).