17.24% rise . Trading halt, page-4

LOL Chill,

We did have a frac tree on standby at the time. I remain hopeful however that the CT has been
re-commissioned quickly.

On an entirely different note; For those that like a bit of light reading, here are some excepts of a recent
conference in USA discussing the various issues involved with unconventional plays in the Eagle Ford
Shale. Lets not forget that this is a shale that has now over 4000 wells drilled since 2008 and they
are still experimenting & improving. Puts our first CONCEPT well in a new shale play into perspective.
Some of the issues under discussion ;

1.
Showing How Different Well Design, Stage Design And Cluster Density Have Impacted Performance In The Upper, Upper Middle And Middle Eagle Ford

Evaluating a producer’s recent production performance results relative to well spending to determine the economic performance of the well•Understanding how producers are deciding on well spacing and how these decisions have impacted overall production performance relative to costs•Assessing which reservoir characteristics are being used to determine the point of diminishing returns in stage spacing•Explaining how optimum cluster spacing footage improved the stimulation of rock volume in each Eagle Ford zone.


Exploring How Reservoir Simulation Is Being Used To Model The Performance Of Liquid Rich Shale Systems And Optimize Production And Development Of The Eagle Ford

Analyzing geomodeling, gridding, PVT, flow models, hydraulic fracture modeling, microseismic and SRV estimation to accurately optimize wells and completions spacing•Proposing a reservoir simulation workflow to address optimum grid design, proper capture of SRV and natural fractures corridors and adequate modeling of PVT properties

Hearing Which Reservoir Characteristics And IP Readings Are Being Used To Determine Well Spacing And Increase Production Relative To Costs In The Eagle Ford

80 vs. 100 acre spacing: Concluding optimal number of wells per acre to optimize recovery without incurring unnecessary cost•Learning how well spacing decisions can be effectively transferred between gas, oil and condensate window to drive down the costs for multiple projects Monitoring IPs for every incremental well to determine correlation between footage between wells and production performance•Examining how variations in reservoir thickness are being utilized to reconfigure and optimize well spacing decisions

Scrutinizing Which Well Design Parameters Are Being Used To Effectively Minimize Well Interference

Determining the narrowest footage between wells that can be allowed to optimize drainage while mitigating interference•Assessing results from field tests to determine the extent to which interference is resulting in production and reserve loss

Comparing Production Results To Assess How An Eagle Ford Well Has Responded To Variations In Frac Spacing And Clusters Per Stage And Determine The Most Cost Effective Design

Understanding best practices for determining accurate cluster spacing for different stage length variations in different Eagle Ford reservoirs•Evaluating production changes relative to spacing variability to establish incremental recovery vs incremental cost•Understanding how microsesmic is being used to determine optimum cluster footage necessary to augment stimulation of rock volume•Assessing how to effectively place plug to plug spacing to maximize hydrocarbon recovery•Analyzing production data showing the optimal number of perforations per stage to inform decisions on perf strategy•More cluster/less spacing vs less cluster/greater spacing: Relating production results to cost of completions to economically divide clusters•Fewer clusters/more stages vs more clusters/fewer stages: Evaluating the extent to which cement quality impacts the feasibility of adding additional clusters.

Linking Frac Size With Production Results To Reach Maximum Stimulated Reservoir Volume At The Lowest Cost

Assessing production results from wells using smaller fracs vs. bigger fracs to identify achievable stimulated rock volume relative to cost•Evaluating if significant production returns are achieved from fractures that are farther away from the heel of the well to plan optimum number of fracs.

Comparing And Contrasting How Different Frac Fluid, Proppant And Pump Rates Are Impacting Well Performance: Results From Empirical Studies Across The Life Cycle Of The Well In Each Play

Comparing lithology of the rock in each play to understand the extent to which completions design requirements vary across a large acreage•Exploring practices in design testing being used with multiple reservoir parameters to identify significant completion changes between formation•Plug and perf vs. Slotted liners.•Optimum fluid and proppant volumes.•Optimum stage spacing•Slick water/hybrid gel/ Cross link gel•Hearing how each parameter influences final production performance in the respective plays.

Matching Rock Types To Fluid Types: Identifying Which Fluid Will Provide Maximum Stimulation In Different Reservoir Types

Developing a cost vs. production profile for slick water, cross-link and hybrid fluids to reduce expenses and maximize hydrocarbon recovery•Matching reservoir characteristics, fluid types and production performance from limestone and marlstone formations to identify optimal fluid type for each rock type•Analyzing results from fluid sensitivity studies taken with cores to establish the effect of pumping different fluid types on the performance of the well•Discussing fluid sensitivity for reservoir rock types with large ash deposits to investigate the impact of fluids on a non-homogenous reservoirAssessing the correlation between high temperature systems and fluid types to ensure optimal systems are selected•Examining results of rock exposure to distilled water and water with high KCI concentration to determine least damaging fluids for various rock types•Analyzing continuous streams of production results to assess the effectiveness of adding chemicals to fluid systems to keep proppants in place.

Slickwater Vs Hybrid Vs Cross-Link: Determining Which Fluid System Is Providing Maximum Stimulation And Highest Rate Of Recovery: Case Study

Comparing results from wells in the same area, using different fluid types to determine which yielded highest recovery relative to costs•Optimal fluid volumes: How accurate fluid volumes for different reservoir types were distinguished to avoid unnecessary fluid injection costs.

Examining The Impact Of Reservoir Depth On Proppant Strength And Size To Optimize Selection

Determining the influence of reservoir depth on closure stresses and crushing on the proppant in unconventional wells•Understanding pressure differentials to determine correct proppant types for pressure variations in reservoirs•Developing a realistic cost-benefit assessment for sand and resin coated proppants to ascertain whether improvement in performance justify extra cost•Correlating reservoir fluids and proppant selection to determine optimum proppant strength and size for a dry gas reservoir vs black oil reservoir•Understanding proppant selection criteria for high GOR and low GOR reservoirs to achieve highest recovery in every section.

How Microseismic Data Is Being Into The Workflow To Facilitate Completion Optimization Decisions In Complex Fracture Networks

Utilizing microseismic to detect fracture patterns in different reservoirs within the same play to evaluate the extent to which variability exists from:•North to South•East to West•Comparing fracture patterns in the gas window vs the fluid window vs the condensate window to determine how the response of the rock varies•Hearing how microseismic is used to determine how far out of the wellbore the proppant reached and how much gross rock volume was stimulated•Assessing the variability in the optimal number of times microsiesmic needs to be run relative to fractures in pre-existing zones to inform operational decisions.

Utlizing Frac Modelling To Assess The impact of Completion Design, Fracture Spacing, Fracture Sequencing and Well Spacing on Fracture Complexity in the Eagle Ford

Understand the factors influencing fracture trajectories and the implications of fracturing pressure data in horizontal completions•Evaluating the impact of completion variables such as proppant-mass and fracture spacing to optimize the generated fracture complexity•Presenting a case study showcasing the impact of time between fractures and fracture sequencing on observed fracture complexity•Detailing the impact of fracture spacing and well spacing on probability of fracture complexity for infill wells in horizontal well pads.

Complex business this fraccing.

GLTAH