This course discusses the fundamental sand control considerations involved in completing a well and introduces the various sand control techniques commonly used across the industry, including standalone screens, gravel packs, high rate water packs and frac-packs. It requires only a basic understanding of oilfield operations and is intended for drilling, completion and production personnel with some sand control experience who are looking to gain a better understanding of each technique’s advantages, limitations and application window for use in their upcoming completions.
Cement sheath is a critical barrier for maintaining well integrity. Formation of micro-annulus due to volume shrinkage and/or pressure/temperature changes is the major challenge in achieving good hydraulic seal. Expansion of cement after the placement is a promising solution to this problem. Expanding cement can potentially close micro-annulus and further achieve pre-stress condition because of the confinement. Primary aim of this paper is to investigate mechanical integrity of different pre-stressed cement system under loading condition.
To achieve the objectives, finite element modelling approach was employed. Three dimensional computer models consisting of liner, cement sheath, and casing were developed. Pre-stress condition was generated by modelling contact interference at the cement-casing interface. Three cement (ductile, moderately ductile, and brittle) were considered for simulation cases. Wellbore and annulus pressure were applied. Resultant, radial, hoop, and maximum shear stresses were investigated at the cement-pipe interface to assess mechanical integrity. For comparison purpose, similar simulations were conducted using cement sheath without pre-stress and cement system representing uniform volume shrinkage and presence micro-annulus.
For constant wellbore pressure, the radial stresses observed in all three types of cement system were practically similar and decreased as pre-stress was increased. Hoop stress also reduced with increase in compressive pre-load. However, their absolute values were distinct for different cement types. These results indicate that cement system with compressive pre-load can notably reduce the risk of radial crack failure by providing compensatory compressive stress. However, on the contrary, the maximum shear stress developed at cement-pipe interface, increased because of pre-load. This can compromise the mechanical integrity by reducing the safety margin on shear failure. Thus, the selection of expansive cement should be made after carefully weighing reduced risk of radial failure/debonding against the increased risks of shear failure.
This paper provides novel information on expanding cement from the perspective of mechanical stresses and integrity. Modelling approach discussed in this work, can be used to estimate amount of pre-stress required for a selected cement system under anticipated wellbore loads.
Anis, Apollinaris Stefanus Leo (Schlumberger) | Syarif, Zilman (Saka Indonesia Pangkah Limited) | Setiawan, Ade Surya (Schlumberger) | Hidayat, Azalea (Saka Indonesia Pangkah Limited) | Murtani, Anom Seto (Saka Indonesia Pangkah Limited)
Ujung Pangkah Field which located at offshore East Java Indonesia, is known for its challenging nature from geological, reservoir and drilling perspectives. Drilling experiences in this area shows severe wellbore instability in overburden shale and in fractured carbonate reservoir. Hydrocarbon production directly exacerbate drilling problems and production issues that were not expected came earlier than predicted, for example early water breakthrough. At least two or three operators facing similar severe wellbore instability problems in the area.
Due to the complexity of subsurface systems and coupled interactions between depletion and stresses, the present-day stress state in Ujung Pangkah Field which have undergone production will be different from the pre-production stress state. Therefore, a comprehensive analysis will require numerical modelling involving coupling of 3D geomechanical model with fluid flow during production operations from dynamic model. Present-day stress state is subsequently used for wellbore stability analysis of planned development wells in Ujung Pangkah Field. Investigation of the behavior of natural fractured reservoir during depletion and its impact to reservoir management is also attempted. Two-way coupling of geomechanic and dynamic models were conducted whereby porosity and permeability update due to production were simulated based on uniaxial pore volume compressibility tests. Hence, porosity and permeability of fractures are not considered static anymore but dynamic due to stresses changes and production.
The result of coupled simulation is able to reduce wellbore instabilities significantly in the planned well. The stable mud weight windows for planned wells are extracted from the model. The stable mud weight window in the reservoir interval is narrow to no stable drilling window in all the planned wells due to depletion. In general, the preferred direction to drill, requiring lowest mud weights, is in the direction of minimum horizontal stress which in this case is Northwest-Southeast (NW-SE). However, it was found that azimuthal dependency of mud weight is insignificant due to low horizontal stress anisotropy.
Reservoir compaction and sea-bed subsidence were also calculated using the outputs from the model. The result is useful for completion and platform integrity.
Summary We propose a two tiered inversion strategy that aims to address and better explore the solution space during seismic inversion and reservoir characterization. First a range of plausible geological prior scenarios are defined in terms of layer configurations and horizon/picking uncertainty, number of facies and their corresponding abundances, and rock property trends and relationships (with associated uncertainties). Then, per scenario, stochastic Markov chain Monte Carlo sampling (McMC) is performed to create equiprobable realizations from the posterior distribution. The benefit of this approach is twofold; first of all, no prior low frequency model is stipulated by the operator, with the low frequency content instead being derived through iterative fitting of seismic amplitude data via sampling from facies based elastic property trends. This provides a novel way of exploring uncertainty in the low frequency end of the earth spectrum.
Not too long ago, horizontal drilling revolutionized the petroleum industry. Emerging logging-while-drilling and geosteering technologies helped bring about multilateral, maximum-contact, and smart-completion wells, allowing reservoirs to be developed and produced much more efficiently and economically. This increased recovery, thus boosting reserves. In the process, formation evaluation plays a critical role in determining whether a producer or an injector is successful. More recently, efficient mass horizontal drilling and optimized multistage massive fracturing have turned traditionally nonreservoir source rock into sweet spots of energy strategy on a global scale.
This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 186343, “Review of Coalbed Methane Prospects in Indonesia,” by C. Irawan, D. Nurcahyanto, I.F. Azmy, J.A. Paju, and W.M. Ernata, SKK Migas, prepared for the 2017 SPE/IATMI Asia Pacific Oil and Gas Conference and Exhibition, Bali, Indonesia, 17–19 October. The paper has not been peer reviewed.
In 2005, two companies began studying the potential of seismic operations for the Kutai and South Sumatra basins (Fig. 1). However, the progress of coalbed-methane (CBM) operations has been slow for several reasons. This paper reviews the efforts to exploit CBM resources in Indonesia, the challenges these efforts have faced, and possible solutions that can make operations more efficient and profitable.
Despite the current industry climate, operators in Indonesia continue to pursue CBM production opportunities. The Indonesian government has stipulated in its contracts with these companies that current operations must yield production within a set time frame, highlighting the importance of making such operations cost-effective.
Currently, many methods are avail-able to drill CBM wells. In early efforts to exploit CBM wells, contractors used conventional methods to drill a well at a target depth of 500 to 800 m at a high operational cost, but time frames were not met. Of 51 exploration contract areas involving CBM in Indonesia, only 17% of these have fulfilled their commitment. Obstacles that prevent success in these endeavors are often nontechnical in nature, including organizational difficulties (suboptimal financial conditions of operators), land- and permit-acquisition issues, challenges in community relations, gaps in the supply chain, and problems with access and infrastructure. Standard operating procedures (SOPs) are difficult to formulate and implement under these conditions. The CBM well must follow industry operational standards, which, when com-pared with standards involved in the mining industry, for example, involve a higher level of technology and the need for more permits and, thus, a greater cost.
Indonesia CBM Contract Area Indonesian unconventional prospects are essentially divided into two areas, Sumatra and Kalimantan. These areas contain the most abundant coal-seam prospects. However, proved resources do not equal the estimated resources calculated more than a decade ago.
Geologically, target coal seams in the Sumatra and Kutai basins differ only in their depth. The target coal seams in Sumatra are shallower than those in the Kalimantan region. In both basins, the cost per well is high.
Extensive discoveries of basement hydrocarbon reservoirs have been made in many places of fractured granite and carbonate basement in the world. Important hydrocarbon findings were achieved in fractured granitic basement in Chad and Indonesia by means of UBD and MPD technologies.
The granitic basement in Chad and Indonesia featured with hydrostatic pore pressure gradient with narrow density windows and well developed fractures. The pore pressure coefficient of the basement of Chad was predicted in between 1.02-1.06, and an underbalanced drilling (UBD) technology with a micro-foam drilling fluid was used to make an attempt on reducing drilling fluid losses; the pore pressure coefficient of the basement of Indonesia was estimated to be 1.04, and an underbalanced managed pressure drilling (UB-MPD) technology with a synthetic based drilling fluid was utilized to avoid drilling fluid losses and in favor of hydrocarbon discovery.
Different drilling technologies or modes received different results although drilling in same fractured granitic basement with similar pore pressure. Losses and kicks continued almost all the time during drilling, coring and wireline logging in some wells during UBD in Chad. Losses happened as soon as the rig pump started while overflow occurred no sooner than the rig pump stopped. However, the potential problem of losses and kicks was completely controlled by utilization of UB-MPD technology in Indonesia. No losses were found during underbalanced managed pressure drilling, tripping, connection, and circulation. Nevertheless, both basement hydrocarbon reservoirs in Chad and Indonesia have been obtained important discovery. Crude oil returned to the surface during UBD in Chad and abundant natural gas produced during UB-MPD in Indonesia.
Both UBD and UB-MPD technologies are effective to gain the discovery of fractured granitic basement reservoirs. The underbalanced MPD technology, a precisely pressure controlled drilling system, is able to accurately control the annular pressure profile throughout the wellbore, therefore it could effectively achieve safe drilling in narrow density window and cut non-productive time. It is proved to be more effective and safer in drilling of fractured granitic basement.
Abu Dhabi Fields are showing the presence of several leads/prospects with a significant amount of hydrocarbon accumulations, where the faults provide the critical up-dip closure. The classical approach of fault sealing based on the construction of a deterministic juxtaposition and Shale gouge ratio analysis will not work in Abu Dhabi fields, as most of the section is mainly consisting of carbonates and the faulting history is mainly overcoming by strike-slip movement, where the vertical offset along the faults are minimum. Therefore, implementing a new approach based on construction of an integrated modeling using well logs, seismic, outcrop analogues, 1D MEM and 3D MEM, complemented with modeled and measured pressure data is necessary.
The sealing behavior of faults is known to control aspects of hydrocarbon migration and reservoir distribution in space and time, the least understood factor in petroleum system. Fault planes can be sealing and prevent flow of fluids in one time and be leaking in another time. It can be sealing for oil and leaking for gas/oil or it can be sealing at one horizon and leaking at another horizon. This paper provides a workflow for assessing the risk of fault seal in undrilled prospects. This is an integrated approach based on statistical analysis of a database of sealing and non-sealing faults to solving fault seal issues, which involves a combination of: Detailed microstructural, geometries and petrophysical property analysis of fault rocks; fault zone poroperm histories, sealing mechanisms, sealing capacities, stability and the timing of fault activity during the burial history. In addition to the geomechanical modeling aspects with the characterization of fault array geometry, population, distribution of sub-seismic faults from wells, cores and outcrop data and an evaluation of the seismic scale fault array attributes.
Faulting mechanisms in Abu Dhabi petroleum system have complicated movement histories involving numerous periods of reactivation and, in some cases multiple reversals of fault-movement direction. Therefore, to fully assess fault-seal potential it is necessary to examine the evolution of faults through time and the stress history, in addition to fault characterization, population, sealing criteria, and fault geometry/orientation. The results offer useful insights in the main factors and highlights how the faults behave, with risk evaluation, in terms of uncertainty ranges and sensitivities. As a result, the explorationist will have indication to remove the "uncertain" results. In addition, well data, 3D seismic data, and advanced interpretation tools can make it possible to accurately characterize the geometry/distribution and kinematics of faults, the in situ pressure differences across them and the possible compartmentalization.
During this low oil price era, E&P operators are challenged to reduce operating costs by evaluating their production system. Integrated production model (IPM), which combined subsurface model and surface production system, is a tool that can be utilized to evaluate the existing production system and to arrange the upcoming production strategy. This paper focuses on Kaji-Semoga oil field which consists of three field processing stations, three compressor stations, 130 ESP and 63 gas lift (GL) wells.
The system evaluation started with evaluating the total GL injection required for all GL wells to observe the opportunity to increase the oil production or reduce the active compressor. This required gas lift performance curve for each wells with sensitivity to the various well head pressure. The ESP, as equipped with variable speed drive, can be optimized in accordance to the pump capacity and facility constraints. The artificial lift reliability was also evaluated to reduce the oil deferment and to foresee the next production strategy. The IPM for Kaji-Semoga was built to integrate those issues.
Based on the IPM, the total GL injection rate can be reduced by up to 17% while maintaining the total oil production. With the aim of cost optimization by saving the gas fuel and reducing compressor cost, then the gas lift compressors had been shut down and relocated to another asset. As the result, 24% of total annual compressors cost was saved. From the artificial lift reliability evaluation shows that GL system reliability was reduced along with the gas shortage, whereby contributed 71% of total oil deferment. The artificial lift conversion from GL to ESP then selected as a solution. The strategy for shutdown the next gas lift compressors was then generated in accordance with the artificial lift conversion schedule and the gas lift network distribution. To overcome the limitation of liquid handling capacity at the field stations due to the conversion project, the IPM could optimize the GL and ESP simultaneously thus total fluid production can be maintained at a minimum level by continuing to retain the oil production.
The paper describes some of lesson learned in constructing and utilizing the IPM as an effective tool, not only to optimize the existing production system, but also to generate the future production strategy, cost reduction opportunity and operation maneuver.
This paper describes an efficient approach to evaluate waterflood connectivity performance in complex compartmentalized reservoir, the objectives are to increase the oil production performance and manage mature fields effectively, and also to enhance ultimate recovery in the long run. It is also very useful to get better understanding of detail reservoir characterization, reservoir internal architecture, reservoir distribution, pressure monitoring and subsequent water flood sweep pattern efficiency. Multi-disciplinary methods applied to maximizing all of data and create strong analysis. The first phase is deep sub-surface analysis in property distribution, simultaneous inversion, 4D time lapse seismic and sweep pattern analysis, those analysis have been done to get comprehensive interpretation of reservoir characterization and waterflood monitoring. The second phase is tracer injection, we implement tracer in several wells to ensure connectivity from injector to several producers are efficient and optimal. These methods were performed for several regions of this area which contains a large number of well, nearly 200 wells consist of vertical, deviated and horizontal wells. Reservoir distribution in Windri area interpreted as stacking channel with high sinuosity geometry. This reservoir consists of predominantly of marginal marine claystone interbedded with deltaic sandstones, thin limestone and coal. Bio-stratigraphic analysis from cores shows that the reservoir was deposited in estuarine setting, interrupted by a brief shallow marine incursion. Seismic amplitude mapping at the upper base Gita horizon reveals a system of meandering channels. Compartmentalised reservoir in Windri area divided into 5 sweep pattern to make analysis more detail and accurate. Each of compartment have different characteristic, this is the challenging part in Windri area. East of windri area channel divided into 4 channels and it shows the evolution and movement of the channel that can control the property distribution and reservoir connectivity. Group two shows good result from tracer injection and it is supporting the interpretation of reservoir distribution and characterization within the area. Integrated 4D time lapse seismic generate pressure monitoring movement from each of waterflood phase. The results of this integrated study implementation are excellent, the ineffective water injection pattern now become effective, there is no unavailing injection well, every pattern is connected and link to each other, so that we can achieve our goal to enhanced recovery factor from 16% to 20%. Reservoir characterization using multi-discipline method reduce uncertainty of heteroginity sand and fluid prediction. Integrated waterflood analysis has been implemented for prospect generation, production optimization and overcome pressure degredation in this area.