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.
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. For example, the relative permeability that increases in the direction of increasing oil saturation must be the oil relative permeability. The endpoints of the relative permeabilities in Figs. 1 and 2 are defined by the critical gas saturation Sgc and the residual oil saturation Sor. Common names and symbols for some saturation endpoints are listed in Table 1.
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,
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. 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.
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.
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).
ABSTRACT: Fracture initiation often follows a plane different to the final fracture propagation plane. Stress reorientation in the near-wellbore region may promote fracture initiation of different orientation than the one dictated by the far-field stresses. A three-dimensional numerical analysis using a geomechanical model is performed to assess an analytical orientation criterion for fracture initiation in perforated wellbores. This is accomplished by considering the tangential stresses on two points (extremes) around the base of the perforation; one for the initiation of transverse fractures and another for the initiation of longitudinal fractures. In-situ stress state, wellbore pressure, perforation geometry and the formation’s mechanical properties are independent variables that are shown to control the orientation of the initiated hydraulic fractures; the dependent variable.
We find that it is likely for typical hydraulic fracture treatments to achieve longitudinal fracture initiation in horizontal wells as transverse initiation will only occur over a narrow window of conditions including low wellbore pressure at breakdown and formation tensile strength. In contradiction with existing analytical models, the numerical study shows that the tangential stress which induces transverse fracture initiation is a function of wellbore pressure just as the stress inducing longitudinal fracture initiation. This makes the breakdown pressure window for transverse fracture initiation smaller compared to the prediction of the analytical model.
Hydraulic fracturing is a reservoir stimulation method used since the 1940s. This is accomplished by high pressure fluid injection which either creates cracks that propagate through the rock matrix or can reopen natural pre-existing fractures. Commonly, 20 to 40 fracture stages are placed in a horizontal well with four or more fractures pumped per stage simultaneously. The industrial impact of this technology has been massive and is responsible for the advances in the development of tight unconventional petroleum resources such as shale gas and oil (Michael, 2014 and Michael, 2016a).
The hydraulic fracture orientation controls the well productivity from hydrocarbon reservoirs. In this study we investigate critical parameters controlling the orientation of hydraulic fracture initiation in perforated horizontal wellbores. Productivity from low permeability (“tight”) formations is greatly improved having multiple fractures oriented transversely rather than longitudinally relative to a horizontal wellbore. This is useful for completion design engineers; when targeting low permeability formations, horizontal wells should be made to induce multiple transverse fractures, as opposed to longitudinal fractures which are more effective in higher permeability formations.
Interpretation of logs from an exploration pilot well and a lateral drilled from the pilot in the Late Cretaceous Natih formation in the Sultanate of Oman was used for designing a multistage hydraulic fracturing treatment. A high-tier logging suite including borehole image, advanced dipole sonic, geochemical, and triple combo data was acquired in both wellbores. The objective of the pilot hole was to select the best landing point in terms of reservoir quality (RQ) and completion quality (CQ) so that a horizontal well could be drilled and multistage stimulations performed in the organic-rich Natih B source rock.
In contrast to much of North America, significant tectonic forces are frequently present in this region. The geomechanical setting might thus strongly affect hydraulic fracture initiation, propagation and proppant placement. It therefore plays an important role in lateral landing point selection. Borehole images, integrated with petrophysical and geomechanical log properties, were used to identify the optimum landing zone. Breakouts as well as longitudinal and transverse drilling-induced fractures were identified on the pilot borehole images over the Natih Formation, indicating a large horizontal stress anisotropy and a compressional tectonic setting. An interval from which vertical hydraulic fractures would initiate at low initiation pressure and grow vertically to contact intervals with good RQ was selected as the target lateral landing point. Image and dipole sonic data were acquired in the horizontal well, and both longitudinal and transverse induced fractures were identified. Those data were used to selectively place hydraulic fracturing stages. Diagnostic injection tests on each stimulation treatment confirmed low fracture initiation pressures and the creation of vertical hydraulic fractures, thus validating the selection of both the landing point and the location of the hydraulic fracture initiation points. All treatments were successfully placed to completion.
This paper demonstrates that a workflow based on the combination of image and dipole sonic logs in both a pilot well and a lateral drilled from the pilot enables the creation of vertical hydraulic fractures at moderately low initiation pressures and successful placement of stimulation treatments in the lateral. This technique shows promise for effective hydraulic fracturing in regions where significant tectonic forces are present.