Transverse fractures created from horizontal wells are a common choice in tight and shale gas reservoirs. Previous work has shown that proppant pack permeability reduction due to non-Darcy flow in a transverse fracture from a horizontal well causes significant reduction in the fracture performance when the gas formation permeability exceeds 0.5 md. There are other configurations and architectures such as aligning the well trajectory with the fracture, either by drilling horizontal wells in the direction that results in longitudinal fractures or by just sticking with drilling vertical wells. However, when drilling and fracturing costs are considered, productivity is not the only optimization consideration.
The field example illustrates a case when the apparent choice to use transverse fractures from horizontal wells proved to be suboptimal from the productivity perspective, but fundamental considering economics. Parametric studies for permeability ranging from 0.01 to 5 md illustrate the importance of economics in addition to physical performance. For similar reservoir characteristics, the optimum fractured well architecture varies considerably, and therefore an extensive reservoir engineering approach may be necessary beyond the well completions and/or current prejudices and inadequate understanding.
Al Hamad, Abdullah (Halliburton) | Abdul-Razaq, Eman (KOC) | Al Bahrani, Hasan (KOC) | Surjaatmadja, Jim Basuki (Halliburton) | Bouland, Ali (Kuwait Oil Company) | Turkey, Naween (KOC) | Brand, Shannon (Halliburton) | Al-Saqabi, Mishari Bader (Kuwait Oil Company) | Al-Zankawi, Omran (Kuwait Oil Company) | Vishwanath, Chimmalgi (KOC) | Gazi, Naz H. (Kuwait Oil Company)
There are many ways to stimulate an unlined openhole horizontal well using acid. The simplest way is to just pump acid into the well (i.e., bullhead) without placement control. However, this can often be ineffective. Although still used, such approaches can create massive enlargements at the entry point or high injectivity area, thus causing ineffective treatments and re-entry issues. Wellbore collapse often follows. The use of coiled tubing (CT) as a "pin-point?? delivery method is therefore preferred. Using CT allows dispersal of the acid either uniformly or intermittently along the lateral, as desired. CT also allows acid washing to be performed, which is another common process that can improve stimulation without much additional expense to the operator. Using a jetting tool with many jets, acid can be sprayed onto the wellbore wall, and the active agitation caused by the acid-wash process increases the chemical reactivity of the acid at the desired locations.
Another beneficial approach of using CT is the hydrajet assisted acid fracturing (HJAAF) method. With focused jetting of acid at much higher pressures, the process initiates microfractures in the wellbore walls. When etched with acid, this approach effectively bypasses near-wellbore (NWB) damage much deeper than common washes, thus providing much better results. Further modification of the process by exerting high annular pressures offers the capability of delivering medium to large fractures.
This paper discusses two HJAAF processes uniquely combined into one process used in two large horizontal wells. Because of the large dimension of the inner diameter (ID) of the wells combined with the small production tubing the tool must pass through, the implementation had to be further improved by using a unique jetting mechanism, which positioned the jet nozzles closer to the target. Actual results of such stimulations are presented.
The directional drilling companies in oil industry usually provide well placement services using proprietary geosteering software that utilize conventional Logging-While-Drilling (LWD) data. Usually online access to the recorded logs is available to end users, but often very limited capability exists within the oil companies to test geosteering interpretations and advise. Present paper shares the case studies of some wells in which Gas-While-Drilling (GWD) data was used in conjunction with the LWD data for well placement. Furthermore, the Geosteering Module of a third party 3D Geological modeling software was used independently within the West Kuwait Fields Development group of KOC for well placement.
Well D-08 was drilled as vertical producer in a West Kuwait Marrat carbonate reservoir, produced economic quantities of oil during initial testing, but it started cutting high amount of water due to the effect of a fault. Therefore, the well was re-entered and sidetracked at a high angle, away from the fault. Similarly, the U-73 vertical well which encountered poor reservoir facies on flank of the field, was re-entered for productivity enhancement into a thin porous reservoir layer as horizontal sidetrack towards the crest. Both these wells were monitored and geosteered in near real-time using a geosteering software module which combines the overall structural framework provided by 3D geological model, along with the well log responses characteristics from offset wells, to produce a detailed pre-drill model for Geosteering. This is achieved by forward modeling to predict changes in log characters along the planned wellbore profile. The results are displayed both in vertical and measured depth domains along a 2D curtain section with formation tops parallel to the planned well azimuth.
In addition to the conventional LWD logs, the GWD logs generated from advanced gas analysis of the drilling mud were used for geosteering during drilling well D-08 and U-73 re-entry sidetrack wells. The LWD and GWD based geosteering were done independent of each other to test the efficacy of GWD method. Geosteering software and advanced mud gas data have been paired for high angle and horizontal well placement for the first time in Kuwait which successfully guided the well trajectory while drilling.
Hassan, Hany Mohamed (Petroleum Development Oman) | Al-hattali, Ahmed Salim (Petroleum Development Oman) | Al Nabhani, Salim Hamed (Petroleum Development Oman) | Al Kalbani, Ammar (Petroleum Development Oman) | Al Hattali, Ahmed (Petroleum Development Oman) | Rubaiey, Faisal (Petroleum Development Oman) | Al Marhoon, Nadhal Omar (Petroleum Development Oman) | Al-Hashami, Ahmed (Petroleum Deveopment Oman)
A cluster area "H" consists of 4 carbonate gas fields producing dry gas from N-A reservoir in the Northern area of Oman. These fields are producing with different maturity levels since 1968. An FDP study was done in 2006 which proposed drilling of 7 additional vertical wells beside the already existing 5 wells to develop the reserves and enhance gas production from the fields. The FDP well planning was based on a seismic amplitude "QI" study that recommended drilling the areas with high amplitudes as an indication for gas presence, and it ignored the low amplitude areas even if it is structurally high. A follow up study was conducted in 2010 for "H" area fields using the same seismic data and the well data drilled post FDP. The new static and dynamic work revealed the wrong aspect of the 2006 QI study, and proved with evidence from well logs and production data that low seismic amplitudes in high structural areas have sweet spots of good reservoir quality rock. This has led to changing the old appraisal strategy and planning more wells in low amplitude areas with high structure and hence discovering new blocks that increased the reserves of the fields.
Furthermore, water production in these fields started much earlier than FDP expectation. The subsurface team have integrated deeply with the operation team and started a project to find new solutions to handle the water production and enhance the gas rate. The subsurface team also started drilling horizontal wells in the fields to increase the UR, delay the water production and also reduce the wells total CAPEX by drilling less horizontal wells compared to many vertical as they have higher production and recovery. These subsurface and surface activities have successfully helped to stabilize and increase the production of "H" area cluster by developing more reserves and handling the water production.
The purpose of this paper is to introduce various offshore platform conceptsthat can be employed in ice infested waters, particularly shallow waters,depths varying from 65 ft to 500 ft. The paper illustrates five innovativeplatform concepts that for arctic drilling. The proposed platform conceptswould have ability to withstand extreme ice, wind, wave and temperatureconditions to extend the drilling seasons either near to winter sever storm orfor round the year operation. The platforms are designed to operate indifferent water depths in different part of the arctic by accommodating thedrilling structures and equipment on the deck. The emphasis is on theefficient of breaking, moving ice sheets around the structure and withholdingthe topside loads. Some of the platform concepts are fixed and others aredeveloped from the floating solution and the technical details are presented inthis paper.
Ice gouging of the seabed is an issue in cold regions where ice or icebergscan contact the seabed. This creates a design challenge as pipelines must beburied to a sufficient depth to resist loads transferred through the soil tothe pipeline. However, as trenching and backfilling is expensive andtechnically challenging, a goal needs to be to optimize the depth ofburial.
Conventional methods to evaluate the ice gouge loading on a buried pipelinerely on decoupled analysis of the ice-soil and soil-pipe responses,which is believed to be a conservative approach and not adequatelyrepresentative. In this paper, ice gouging is investigated usingadvanced numerical modelling techniques to reduce this conservatism and betterquantify the loads experienced by the pipeline due to ice gouges.
The Coupled Eulerian Lagrangian (CEL) finite element method is utilized in aseries of comparative studies based upon available centrifuge and full scaletest data. The CEL analysis results in relatively smaller sub-gougedeformation depth than the current guidance suggests, based on centrifugetests. The shallow sub-gouge deformation zone indicated appears to correlatewell with the limited amount of full scale test data available. If the lessconservative CEL result can be validated, significant burial depth reductionscan be achieved.
CEL technology originally developed in the early 1960s however it has notbeen widely used until the late 1990s. The soil behaviour in this matter iscritical, thus the paper investigates the CEL capabilities to implementgeotechnical soil models i.e. Mohr- coulomb and Drucker-Prager yieldcriterion.
Furthermore, the paper assesses the benefits and limitations of usingadvanced finite element methods to investigate ice-soil-pipe interaction,highlighting the constraints and the required further developments for thecurrent technology to enable the industry to better evaluate the risk of icegouging.
This paper characterizes the spatial and temporal variability of riveroverflooding on the sea ice and related pipeline and facility siting concernsfor the nearshore region of the Alaskan Beaufort Sea. This phenomenon occurseach spring during a brief period when river discharge precedes the break-up ofthe landfast sea ice. The river water flows on top of the grounded and floatingsea ice, and can spread several kilometers offshore and encompass vast areas.The overflood waters drain through holes and discontinuities in the ice, andcan create large scour depressions on the sea floor when the drainage rate ishigh. These so called "strudel scours" can constitute a significant designconsideration for subsea pipelines.
A test program, undertaken as part of a C-CORE led Joint Industry Program(JIP), was carried out to investigate the limiting strength and failuremechanisms of seabed gouging ice ridge keels. A test frame was designed,fabricated, commissioned and used in the test program. During tests, methodswere developed to build & test large size keel specimens, and surfaceprofile both keel and soil bed before and after test. Testing consisted ofloading the keel with a surcharge force and initiating a horizontal movement ofsoil bed until keel failure was observed. In total, nine keels weremanufactured and tested under a variety of initial confinement pressuresranging from 0 kPa to 75 kPa. Six tests were conducted with a gravel berm andsoil bed and three tests were conducted using a steel (rigid) berm face andgravel soil bed. A summary of the test results and key observations arepresented in this paper.
A simple, rectangular sub-surface caisson was evaluated using physical andnumerical modeling to develop a method for protecting subsea installationsagainst scouring keels of icebergs on the Grand Banks. This protection strategywas developed to assess the feasibility of the structure as an alternative tocostly excavations used to protect subsea equipment on the Grand Backs. Thescenario considered was an ice keel (i.e., iceberg) scouring over a buriedcaisson, avoiding direct contact but with minimal clearance. A centrifugetesting program, consisting of five tests, formed the basis for calibration ofa finite element model. The first four centrifuge tests were carried out withwater as the pore fluid in order to simulate drained conditions during thekeel-soil-structure interaction. In the field, fully drained conditions may notexist; hence the fifth centrifuge test was conducted using a viscous pore fluidto simulate the partially drained conditions. The numerical analyses wereconducted using the commercially available finite element software packageABAQUS. This study demonstrated that the Coupled Eulerian Langrangian (CEL)technique is capable of modeling slow keel-soil-structure interaction events insand. The numerical model performed satisfactorily in simulating the centrifugetests. The results indicated that such a system can potentially provide theprotection needed for subsea installations in ice infested waters. Althoughthis work was based on the conditions encountered on the Grand Banks, theconcept would be applicable to other regions. Future work should involveevaluating various ice keel-soil-structure interaction scenarios and attackangles, development of Inspection, Repair and Maintenance (IRM) strategies aswell as a detailed assessment of construction and installation issues.
Widening supply and demand gap in natural gas industry, the advent of tight gas policy and increasing interest of operators in tight gas sands and shale has opened new venues for development of unconventional plays in Pakistan.
Middle Indus Basin hosts important gas fields of Pakistan. Most of the wells in this basin are completed in conventional lower Goru Sands. Lower Goru formation consists of inter-bedded sequences of sands and shale. Its unconventional sand and shale plays hold immense potential which has not yet been exploited due to lack of technology and promising economics. Moreover, Sembar shale is the well known source rock in this basin holding large shale gas potential. GIIP estimates for Lower Goru tight sands excluding the shale prospects are 8.4 TCF which are considered pessimistic due to lack of data in many fields.
From the currently suspended or abandoned wellbores of the Middle Indus Basin, a pilot project needs to be defined in each of the fields, to prove the technical and economical feasibility of tight Gas Potential of the Basin. Commencement of production from unconventional sands will enhance the production in a cost effective manner due to availability of infrastructure and facilities.
This paper focuses on the utilization of existing wellbores as well as data set and highlighting additional data acquisition requirements coupled with completion and multi-stage fracturing techniques for designing a pilot project. Case study of a pilot project in one of the fields of this basin is discussed. It encompasses the basic workflow, candidate selection criterion, Geo-mechanics, sector modeling, hydraulic fracture design and risk evaluation coupled with its use in full field development projects.
Background and Introduction
Pakistan's last year 2010-2011 production was about 3.91bcf/d, while its demand was (4.2bcf/d) and supply gap was also started. Since then the production from the conventional fields has decreased, while demand has been increased due to infrastructure and human needs. This huge shortfall in the gas market cannot be fulfilled with existing number of completions/producers. The conventional reserves of the country were 56 TCF out of which the country has already produced 50% of its conventional reserves. The recoverable remaining reserves are 24-28TCF, but will be produced at much lower production rate and in much longer period of time. The country has an infrastructure of Gas Processing Facilities 5bcf/d.