REPORT BY ARIJIT SARMA I joined OIL USA Inc. on October 1 2014 upon transfer from Duliajan FHQ where I was working in C&W/O section, prior to my transfer to OIL USA Inc. Subsequently I was assigned as a Secondee in Carrizo Oil and Gas from 5 th October 2014, wherein I was assigned to Operation department under the mentorship of Fred Miller. Later on I was under Scott Hudson VP Completions and drilling from May 2016 onwards. In addition to this I used to work for Oil USA Inc. for one day in a week for management of the Niobrara asset. During my tenure in Carrizo Oil and Gas and OIL USA Inc. I was fortunate to work and learn about various techniques and operations related to Unconventional Oil and gas asset management. I also had the opportunity to visit field from time to time and witness and learn about drilling, completions, production operation procedures and other practices related to operations of unconventional assets. In this regard it is worth noting that Oil India Limited acquired 20% interest in Carrizo Oil & Gas Inc. shale assets in Niobrara Asset of the Denver–Julesburg (D‐J) Basin in Colorado, USA. The Purchase and Participation Agreement (PPA) with Carrizo was signed on 4th October, 2012 and the acquisition became effective from 1st October, 2012. Out of 63,279.41 net acreages, OIL acquired ~ 12,655.88 net acres of the asset. Oil India USA Inc. Subsequently participated in various AMI’s (Area of Mutual Interest) of the JV and acquired acreages at different point of time at various locations of Niobrara asset as described below. Sl. No AMI NO Oil USA(Net Acreage addition) Time of Participation 1 AMI2 2032.50 December 2012 2 AMI3 476.8459 April 2014 3 AMI4 63.5 June 2014 4 AMI6 399.8 August 2015 This write up is an attempt in my part to share the knowledge gathered with my fellow Oil Indians. The write‐ up not only discuss various technical issues but also business related decision making process adopted by US oil and Gas companies. I sincerely hope that this will encourage my fellow Oil Indians to ask more questions to me about practices adopted by US Oil and Gas companies, which will also help me further in my knowledge enhancement. Any suggestions and recommendations by others are welcome and I am eagerly waiting to hear from others.
Transcript
REPORT BY ARIJIT SARMA
I joined OIL USA Inc. on October 1 2014 upon transfer from Duliajan FHQ where I was working in C&W/O section,
prior to my transfer to OIL USA Inc. Subsequently I was assigned as a Secondee in Carrizo Oil and Gas from 5th
October 2014, wherein I was assigned to Operation department under the mentorship of Fred Miller. Later on I
was under Scott Hudson VP Completions and drilling from May 2016 onwards. In addition to this I used to work
for Oil USA Inc. for one day in a week for management of the Niobrara asset. During my tenure in Carrizo Oil
and Gas and OIL USA Inc. I was fortunate to work and learn about various techniques and operations related to
Unconventional Oil and gas asset management. I also had the opportunity to visit field from time to time and
witness and learn about drilling, completions, production operation procedures and other practices related to
operations of unconventional assets.
In this regard it is worth noting that Oil India Limited acquired 20% interest in Carrizo Oil & Gas Inc. shale assets
in Niobrara Asset of the Denver–Julesburg (D‐J) Basin in Colorado, USA. The Purchase and Participation
Agreement (PPA) with Carrizo was signed on 4th October, 2012 and the acquisition became effective from 1st
October, 2012. Out of 63,279.41 net acreages, OIL acquired ~ 12,655.88 net acres of the asset. Oil India USA Inc.
Subsequently participated in various AMI’s (Area of Mutual Interest) of the JV and acquired acreages at different
point of time at various locations of Niobrara asset as described below.
Sl. No AMI NO Oil USA(Net Acreage addition) Time of Participation
1 AMI2 2032.50 December 2012
2 AMI3 476.8459 April 2014
3 AMI4 63.5 June 2014
4 AMI6 399.8 August 2015
This write up is an attempt in my part to share the knowledge gathered with my fellow Oil Indians. The write‐
up not only discuss various technical issues but also business related decision making process adopted by US oil
and Gas companies. I sincerely hope that this will encourage my fellow Oil Indians to ask more questions to me
about practices adopted by US Oil and Gas companies, which will also help me further in my knowledge
enhancement. Any suggestions and recommendations by others are welcome and I am eagerly waiting to hear
from others.
UNCONVENTIONAL OIL AND GAS RESOURCE
A Brief Idea
What is Unconventional Oil and Gas Resources?
According to SPE Unconventional resources” are petroleum accumulates that are pervasive throughout a large area and not significantly affected by pressure exerted by water (hydrodynamic influences); they are also called “tight formations. The expression “shale oil”, or the more accurate term “tight oil”, is often used to refer to rock formations that do contain oil and that sometimes might actually be shale. The defining characteristic is that the rock is not having sufficient porosity or permeability to allow oil or gas to flow out Regardless of how they are produced or the rock they come from, unconventional oil and natural gas are essentially the same as their conventional counterparts. The term “unconventional” simply refers to the methods that are used, as well as the types of rock from which the oil and natural gas are produced.
Not always, is a pocket of oil and gas available to be retrieved by drilling and pressure naturally allowing the flow of gas. In this case, unconventional drilling comes in handy. Unconventional is a method that allows to drill down, drill horizontally, and fracking occurs. This allows oil and gas to be flowing from tight sands that we normally could not retrieve with conventional methods of drilling. In a nutshell unconventional resources are produced from tight sands by application of horizontal drilling and hydraulic fracturing unlike other conventional oil and gas resources.
Some of the key attributes for commercial viability of Unconventional Oil and gas resources are:
• Depth ( Pressure and Temperature) • Burial and Maturity • Source Rock Content • TOC (Total Organic Content) • Thickness • Fraccability • Oil/Gas in Place
“Interesting Fact about Unconventional Resources: Unlike conventional assets gas is below Oil Column” Application of horizontal drilling along with adoption of Fracturing has revolutionized the oil and Gas Industry. In fact success of development of unconventional resources in US has acted as a game changer in Oil and gas Business, which has also resulted to current pressure in commodity price scenario.
How US Unconventional differs from Conventional assets in India
“It’s All about Oil and Gas rights in USA”
In most countries of the world, all mineral resources belong to the government. This includes all valuable
rocks, minerals, oil or gas found on or within the Earth. Organizations or individuals in those countries
cannot legally extract and sell any mineral commodity without first obtaining an authorization from the
government. In the United States and a few other countries, ownership of mineral resources was
originally granted to the individuals or organizations that owned the surface. These property owners had
both "surface rights" and "mineral rights." This complete private ownership is known as a "fee simple
estate."
If we go back in time to the days before drilling and mining, real estate transactions were fee simple
transfers. However, once commercial mineral production became possible, the ways in which people
own property became much more complex. Today, the leases, sales, gifts and bequests of the past have
produced a landscape where multiple people or companies have a partial ownership of or rights to many
mineral assets and real estate parcels.
Most states have laws that govern the transfer of mineral rights from one owner to another. They also
have laws that govern mining and drilling activity. These laws vary from one state to another. If you are
considering a mineral rights transaction or have concerns about mineral extraction near your property,
it is essential to understand the laws of your state.
Mineral Leases and Royalties: Sometimes a mining (Oil and Gas) company does not want to purchase a
property because they are uncertain of the type, amount or quality of minerals that exist there. In these
situations the mining company will lease the mineral rights or a portion of those rights.
A lease is an agreement that gives the mining company the right to enter the property, conduct tests
and determine if suitable minerals exist there. To acquire this right the mining company will pay the
property owner an amount of money when the lease is signed. This payment reserves the property for
the mining company for a specific duration of time. If the company finds suitable minerals it may proceed
to mine. If the mining company does not commence production before the lease expires, and then all
rights to the property and the minerals return to the owner.
When minerals are produced from a leased property, the owner is usually paid a share of the production
income. This money is known as a "royalty payment." The amount of the royalty payment is specified in
the lease agreement. It can be a fixed amount per ton of minerals produced or a percentage of the
production value. Other terms are also possible.
Mineral rights often include the rights to any oil and natural gas that exist beneath a property. The rights
to these commodities can be sold or leased to others. In most cases, oil and gas rights are leased. The
lessee is usually uncertain if oil or gas will be found, so they generally prefer to pay a small amount for a
lease rather than pay a larger amount to purchase. A lease gives the lessee a right to test the property
by drilling and other methods. If drilling discovers oil or gas of marketable quantity and quality, it may
be produced directly from the exploratory well. To entice the property owner to commit to a lease, the
lessee generally offers a lease payment (often called a "signing bonus"). This is an up‐front payment to
the owner for granting the lessee a right to explore the property for a limited period of time (usually a
few months to a few years). If the lessee does not explore, or explores and does not find marketable oil
or gas, then the lease expires and the lessee has no further rights. If the lessee finds oil or gas and begins
production, a regular stream of royalty payments usually keeps the terms of the lease in force. In addition
to a signing bonus, most lease agreements require the lessee to pay the owner a share of the value of
produced oil or gas. The customary royalty percentage is 12.5 percent or 1/8 of the value of the oil or
gas at the wellhead. Some states have laws that require the owner be paid a minimum royalty (often
12.5 percent). However, owners who have highly desirable properties and highly developed negotiating
skills can sometimes get 15 percent, 20 percent, 25 percent or more. When oil or natural gas is produced,
the royalty payments can greatly exceed the amounts paid as a signing bonus.
Oil and Gas Unitization and Pooling: Below the surface, oil and gas have the ability to move through the
rock. They can travel through tiny pore spaces ‐ such as between the grains of sand in sandstone or
through the tiny openings created by fractures. This mobility allows a well to drain oil or gas from
adjacent lands. So, a well drilled on your land could drain gas from a neighbor's land if the well was drilled
sufficiently close to the property boundary.
Most states have recognized the ability of oil and gas to cross property boundaries underground. These
states have produced regulations that govern the fair sharing of oil and gas royalties. These states
generally require drilling companies to specify how oil and gas royalties will be shared among adjacent
property owners when a permit for drilling is filed. The proposed sharing of royalties will be based upon
what is known about the geometry of the oil or gas reservoir compared to the geometry of property
ownership at the surface. This procedure is known as "unitization."
State and Local Laws Always Apply: Most states have laws that regulate mining and drilling activity. There
are also laws that regulate the sale of surface and mineral property. These laws are meant to protect the
environment and all parties involved in property transactions. These laws are the only protection
available to buyers or sellers on issues that are not specifically addressed in the mineral transaction
agreement. Although mineral rights laws are similar from state to state, small variations can make an
enormous difference when applied to individual transactions. In addition, mining and oil and gas
regulations can vary significantly from one state to another. These can also have an enormous difference
when applied to individual transactions. Each transaction is unique and should be carefully considered
before any permanent agreement and investment decision is made.
Working Interest (WI) & Net Revenue Interest (NRI): Working interest owners are obligated to pay a
corresponding percentage of the cost of leasing, drilling, producing and operating a well or unit. In Net
Revenue Interest (NRI), share of production after all burdens (Royalty and overriding royalty) have been
deducted from the working interest.
Land System in US
The Public Land Survey System (PLSS) divides all lands in the public domain to subdivision by rectangular
system of surveys, which is regulated by the U.S. Department of the Interior, Bureau of Land
Management (BLM).
“It’s all about JV (Joint venture in US Oil and gas Business.)”
Like all US Unconventional assets, Niobrara JV has also multiple partners which not only includes
operators and other non‐operators Like OILUSA,IOCL, Haimo etc but also multiple land owners having
mineral rights with varying working interest. An example of this is shown as Exhibit A and B in next pages.
It shows that for a section of mineral acreage (640 acres) there are 33 owners who have working Interest
in it.
As such before commencement of any drilling activity, AFE along with election & participation notice are
prepared and forwarded by the operator to all the partners to seek their participation. As per election &
participation notice the partners(OIL USA one of them in Niobrara JV) have following options:
a. Elect and participate in the drilling and completion of the wells, or
b. Participate in the drilling and completion of the well, and acquire its proportionate share of any
non‐consent interest, or
c. Elect not to participate in drilling and completion of the well, and agrees that its interest will be
subject to a 300% non‐consent penalty under the terms of the Unit Operating Agreement, or
d. Not to participate in the well and not to sign the operating agreement and shall be subject to the
statutory pooling penalty under CRS 34‐60‐116.
If any partner chooses not to participate and does not sign Joint Operating Agreement, the said partner
may be considered as non‐consenting Working Interest owner under respective state oil and gas
commission (COGCC: Colorado Oil & Gas Conservation Commission in case of Niobrara JV) Rule No (530
in Niobrara) and section 34‐60‐116 CRS. The non‐consenting partner is not obliged to pay any of the cost
of the drilling of the wells, however, said partner is subject to non‐consent penalty, until the participating
working interest owner recover 200% of their cost for drilling and completing the wells, plus 100% of
the cost to equip the well. Once those expenses are fully recovered, the non‐consenting partner will be
eligible for working interest in future.
“Economic analysis comes first for US Oil and Gas Business”
The first step for JV partners like OIL USA Inc. after receipt of the election offer/AMI is to find out the
area where proposed wells or acreage are offered and accordingly rank/categorize them as per ranking
criteria adopted.
In this regard, ranking is done based on the section and township of the proposed wells or acreage by
OIL USA Inc. as Area 1, Area 2A or area 3. Reservoir categorization and ranking of the Niobrara play into
various discreet areas like Area 1, Area 2A and Area 3 has been done on the basis of the following
parameters:
a. Geologic/Petro physical Qualities
b. Activity Level
c. Production data
Geological/Petro physical Qualities: Taking 25 ohm resistivity cut off to define limits of prospective
acreage, So‐Phi‐H maps are used to define cut off values of 3 areas which are then correlated with
production data for generating independent type curves of each area. So‐Phi‐H Maps is an industry
standard tool for unconventional asset characterization which uses Oil Saturation (So), Average Porosity
(Phi) and Gross Pay Thickness (H). Higher the value in So‐Phi‐H better is the productivity of the proposed
wells or acreage offered. In case of Niobrara Asset, the following Matrix categorization is used –
So‐Phi‐H cutoff Result
Area 1 4.0 Excellent
Area 2 3.0 Good
Area 3 2.5 Moderate
For example, if proposed wells or acreage offered, falls under T9N58W and T9N59W, we can find from
the map, provided in the next page that these wells/area offered, falls under Area 1 of Niobrara asset
classification.
From the proposed target depth in the well election offer, target bench (A, B or C) of the drilling location
needs to be found out, which is used to determine So‐Phi‐H values of the area as mentioned above. The
example taking T9N58 W is shown in the map provided below. The direction and number of wells
proposed are plotted in this chart to determine what will be expected So‐Phi‐H values for these wells.
As already mentioned, better the So‐Phi‐H value more will be the productivity of these wells. In this case,
it is observed that So‐Phi‐H are higher than 4.0 for the proposed wells and as such, can be considered
as excellent prospect as per the ranking criteria and may be investable based on other factors which
needs to be ascertained.
After ascertaining geological Prospectivity, EUR (Expected Ultimate Recovery) needs to be calculated
based on the production data of the nearby offset wells. Data sources like internal production data, data
from Carrizo production data software Carte, and IHS Energy production data are generally used. In this
regard OIL USA adopts following baseline EUR as per Area classification.
EUR is based on Completion Strategy: The above EUR is only baseline data and for guidance only and
may not be used. Normalized EUR based on production data from the offset wells having different
completion strategy (Extended Reach Lateral: XRL or Short Reach Lateral: SRL) and varying production
rates as per target bench needs to be considered for developing the economic feasibility model.
For example, Noble proposed one well in Township 9N59W and as such a technical evaluation was done
with normalized production data from Carrizo operated wells in Area 9N59W which were completed at
different point of time having different completion strategy.
The wells considered in this case were Castor 2‐36‐11‐9‐59, Ptasnik 1‐30‐9‐59, Timbro 1‐3‐9‐59, and
Timbro 2‐3‐9‐59 which offset to the well proposed. Castor was completed in 2013. Whereas Ptasnik and
Timbro 1‐3‐9‐59 was completed in August 2016, wherein, more proppant was pumped along with
adoption of slick water. It can be clearly seen that wells with more proppant and newer completion
strategy are outperforming the type curve of Area 1 (277 Mboe). Wells completed in August 2016 with
newer completion strategy has shown 20‐30 % higher productivity than the baseline EUR for Area 1 (277
Mboe).
Moreover, it is extremely important to remember that wells completed in the same area (Area 1, Area
2 or Area 3) may show some different production trend. This is because certain minimum rock properties
in terms of porosity, resistivity and thickness are required to make a commercial completion. However,
production results are variable in areas of similar rock quality indicating that production is also
influenced by natural fracturing and proximity to sources of basement heat. Areas with less consistent
overall rock properties are prone to even greater variability in the quality and consistency of the
completions.
In unconventional development and completion, tailor made completion strategy is key as it is expected
that, there will be well to well variation in lithology characteristics, fraccability etc. That’s why average
behavior or normalized production values of various areas needs to be considered for ascertaining
economic feasibility of the well. The same is true also in conventional play, but risk is higher in
unconventional plays. Additionally, downhole equipment failure and weather related problems may
affect the production profile of an individual well from time to time based on the operational behavior
of the downhole components.
Direction of the proposed well: In Niobrara play, most of the wells are drilled in North‐South direction
to align the frac of the well perpendicular to maximum stress direction of the DJ basin. However, in some
cases, wells are proposed in East to West direction for consolidating surface locations and to
accommodate facilities with the adjacent wells. In this regard, OIL USA has observed that wells drilled in
E‐W direction falling within Area 1, shows much lower productivity as compared to wells drilled in N‐S
direction. In fact, it has been observed that wells drilled in E‐W direction underperforms (Chart in next
page) the wells drilled in N‐S direction and has EUR values which is half of the EUR of wells in N‐S
direction. As such, OIL USA feels it will not be prudent to participate in any wells that will be drilled in E‐
W direction until future production data for such wells proves otherwise.
Economic Analysis: After execution of technical analysis, economic feasibility of the proposed
wells/acreage is carried out to ascertain IRR and NPV of the wells/acreage. For economic feasibility E&Y
prepared economic model for OIL USA, has been extensively used (Procedure given in Appendix I) to
determine parameters like IRR and NPV along with sensitivity analysis for various conditions.
The economic model used is a dynamic model as it has features to change completion and drilling period
of proposed wells. This helps to facilitate economic modeling being more flexible to cater to the fact that
sometimes the wells are drilled and kept in inventory instead of completing them as the same is dependent
on prevailing commodity price scenario. Some of the basic input data required for economic modeling is
provided below along with an example data sheet:
General Input data
Valuation Start Date: Jan/17
Valuation End Date : Dec/45
Days in a month: 30.4
Cost escalation %: 2%
Effective monthly escalation %: 0.2%
Gas to Oil Ratio Mcf/ Bbl: 1.5
NGL to Gas Ratio Bbl / mmcf: 78.0
Bcf to mmboe no: 6.0
NGL Pricing %: 30%
Discount Rate %: 10%
Effective Discount Rate %: 0.8%
OIL WI %: 12%
IOCL WI %: 6%
CRZO WI %: 33%
PDP NGL Pricing%: 31%
Gas Shrinkage%: 50%
Fiscal Input data
Royalty%: 17%
Oil Severance%: 5%
NGL Severance %: 5%
Gas Severance %: 5%
Severance Tax %: 5%
Ad Valorem tax credit %: 87.5%
Ad Valorem tax rate %: 5.0%
Assessed Value %: 87.5%
State Tax Rate %: 4.6%
Federal Tax Rate %: 35.0%
AMT Tax Liability %: 20.0%
Ad Valorem ‐PDP and Probable %: 3.5194%
Assessed Value ‐ PDP and Probable: 87.5%
Severance Tax ‐ PDP and Probable: 4.9%
Cost Assumptions
OPEX
Fixed $ / well: 8,300
Escalation: 2.00%
Variable ‐ oil $ / Bbl: 4.29
Variable – NGL $ / Bbl
Variable – gas $ / Mcf: 0.63
Variable – water $ / Bbl: 0.50
CAPEX
Drilling Cost %: 45%
Completion Cost %: 55%
Total Well Cost $ Million: 2.2
Drilling Cost $ Million: 0.99
Completion Cost $ Million: 1.3
Equipment Cost per Well $: 100,000
Pricing Assumptions
Crude Oil Price: NYMEX 5 year scrip price
Gas Oil Price: Henry Hub 5 year scrip price
Transportation Cost/Bbl $: 3.6
Transport Cost as % of WTI: 10%
HORIZONTAL DRILLING AND FRACTURING
Application of horizontal drilling As mentioned almost all unconventional assets are completed by adoption of horizontal drilling along with fracturing. Some of the advantages of horizontal drilling are
Reduced drawdown in the reservoir for a given production rate,
Reduced water and gas coning because of 1, thereby reducing the remedial work required in the future
Increased production rate because of the greater wellbore length exposed to the pay zone
Reduced pressure drop around the wellbore
Lower fluid velocities around the wellbore
A general reduction in sand production from a combination of Items 4 and 5
Larger and more efficient drainage pattern leading to increased overall reserves recovery
Larger contact area in the reservoir enabling more area to be fractured by fracturing to create a network of flow channels to facilitate flow of oil and gas from low permeability tight sands(Unconventional assets)
In development of Unconventional assets lateral length varies according to the mineral acreage rights and target formations. In US unconventional lateral length varies from 4000 feet (SRL: Short reach laterals) up to 9000 feet Laterals. (XRL: Extended reach laterals). Extreme laterals lengths of 18000 feet has also been however achieved in wells like Purple Hayes well in Utica. These Laterals are always fractured as a completion strategy to drain oil and gas from these tight sands. The
concept of fracturing is mainly deployed to tight formations having low permeability to create permeability.
Fracturing is carried out by Injecting highly pressurized water into the rock, which creates a network of cracks that allow the oil and gas to migrate to the well bore. Sand is also pumped as a slurry to keeps the fracks open. Like other Unconventional assets in US, OIL USA Inc.’s wells were also traditionally fracked by using sleeves and ball dropping mechanism with an average of 14‐16 stages per well. However, with current industry trend, wells are now being completed by “Plug and Perf” method with smaller stage intervals comprising of 24 stages per well. The fracking now a days is being progressively carried by slick water instead of gel water fracturing. Slick water fracturing facilitates, bigger volume job per well which also helps in pumping higher fluid compared to earlier. For example in slick water frac by OIL USA Inc. fluid rate is currently 30 Bbl/ft. compared to earlier practice of pumping around 11 Bbl/ft. Every day Quantity of sand (proppant) concentration is also getting increased. As in OIL USA Inc. asset (Niobrara asset) sand quantity has been progressively increased from 760 lbs/ft. to 1100 lbs/ft. along with adoption of smaller size proppant (40/70) which are now more common than bigger size proppant (20/40). Slick water frac uses water with poly‐acrylamide polymers. PAA polymers reduces pipe friction and have low viscosity enabling higher pump rates down the well‐bore (up to 100 Bbl/min) to fracture the formation. However, pumping rate of about 60 Bbl/min only, can be achieved without using slick water. Higher pumping rate helps in achieving more frac height (vertically) compared to a lower rate gel job. Slick water is the preferred fluid for naturally fractured reservoirs like Niobrara. Massive volume of low viscosity fluid facilitates development of a large and complex fracture network. Earlier Carrizo has employed gelled fluids with white sand proppant, where the proppant is suspended in the frack fluid. In a slick water frack, there are no gels. The proppant is not suspended in the fluid and tends to settle
in the bottom of the frack wing. Generally, the Proppant in a slick water frack forms dunes along the bottom of the frack wing.
Slick water frack is cheaper than gelled systems and significantly easier for the Service Company to run and lack of residue results in much cleaner formation compared to gel. However, slick water fracks requires higher rate of pumping. This poses a few issues like more HHP (hydraulic horsepower) is required, and limits the ability to pump higher concentrations of proppant (normally no more than 1‐2 ppg). The higher rate is also going to give you a thinner but more complex frac. The process involves injecting friction reducers, usually PAA polymers. Biocides, surfactants and scale inhibitors can also be mixed in the fluid. Friction reducers speed the mixture. Biocides such as bromine prevent organisms from clogging the fissures and sliming things up downhole. Surfactants keep the sand suspended. Methanol and naphthalene can be used as biocides. Hydrochloric acid and ethylene glycol may be utilized as scale inhibitors. Butanol and ethylene glycol monobutyl ether (2‐BE) are used as surfactants. Slick water typically uses more water than earlier fracturing methods‐‐between one and five million gallons per fracking operation. The below figure shows the effect of slick water vis‐à‐vis gel based fracks These slick water frack jobs are completed by plug and perf method. The procedure for carrying out such a job as in case of Niobrara asset is provided below for better and detailed understanding. Objective To prepare the well for stimulation by breaking down & establish an injection rate through the hydraulic port and perform 24 stages of stimulation via the well’s 4‐1/2”, 11.6# cemented production string using plug and perf, drill out the plugs with CTU, flow test the stimulated well, and turn the well to production.
PROCEDURE PERFORM SAFETY CHECKS AND SAFETY MEETING Perform safety meeting prior to rigging up ANY equipment on location. Discuss the job procedure and objectives with all personnel on location. Document the safety meeting on the report sent to Carrizo. Make note of all potential risks/hazards, and clearly identify an emergency route and emergency vehicle. Also make note of any new or inexperienced personnel on location. Ensure proper Personal Protective Equipment (PPE) is used during the job. Minimums are hard hats, steel toes, and safety glasses Toe Prep 1) RU STS and install a BPV. Remove dry hole tree & install Frac Valve. 2) Hold pre‐rig up safety meeting with all involved company/vendor personnel 3) MIRU workover rig 4) RIH with 3‐7/8” mill and clean out to PBTD, record tag depth 5) RU WL and run CBL with 1500‐2000 psi held at surface, logging from maximum attainable depth up 6) DO NOT LIST T.O.C. ON FIELD LOG. Send log to Houston for TOC interpretation. 7) RU TCP guns with the following configuration: 3 clusters, 2 ft. per cluster, 6 spf, 60 degree phasing, BH
charges. 8) RIH and perforate Clusters 1, 2, & 3 from perf table. 9) RDMO workover rig 10) Install 4‐1/16”, 10,000 psi frac stack & test to 8,000 psi. Frac stack should consist of 1 manual lower
master valve, a cross, 2nd manual master valve with goat head, and cap. Remove BPV. The cross should have two wings consisting of 1 ‐ 4” manual valves both sides of the cross. Manifold should be rigged up on the ground between the Shull 7‐25‐9‐60 and Shull 8‐25‐9‐60 to allow zipper fracking operations.
11) Hold pre‐rig up safety meeting with all involved company/vendor personnel, and obtain rig up schematic from Frac Company. Frac Company needs to pull a water sample from the frac pit for fann test, and return appropriate fann 50 tests to Engineer.
RIG UP FOR STIMULATION 13) Tie the 4‐1/2” x 7” annulus to a flow back tank as a relief line and set up to monitor pressure. 14) Check transfer lines and transfer pumps to frac tanks from the freshwater storage pit. 15) RU flow back equipment & frac tanks for flow back fluids. Spot equipment so fluid can be trucked out as
the well is flowed back while rigging down Frac Company after the frac. 16) Make sure proppant, gel & chemical supplies can be replenished without interfering with the
continuation of the job 17) Review wellhead hookup and verify sufficient wellhead connections/lines to handle job rates (2 X ID2 X
# of lines). Inspect/Confirm ball side 2” line has been laid to ball dropping T to prevent backward flow on ball during drop, and that 4” line has been laid to the wellhead.
18) Test lines to 8,000 psi and inspect all equipment ball/frac side for leaks. 19) Once lines have been primed & tested, run bucket test on blender, hydration unit & back‐ups. 20) Make up fluid sample and confirm sample is cross‐linking at 150 deg F. Record temperatures and pH
and confirm consistency with Fann tests. 21) Obtain sand invoices and confirm that all sand is on location. 22) Review sand and chemical transport schedule with Frac company rep. 23) Conduct pre‐job safety & coordination meeting. Review emergency procedures and designate
emergency vehicles to be used for evacuating any injured personnel. Make sure vendors have sufficient personnel on location or staged nearby to provide relief as needed during the job, (24 – 36 hours). Make sure provisions have been made for crews to be fed and supplied with plenty of drinking water.
PERFORM 24TH STAGE STIMULATION 1) The first 3 clusters have been shot. Begin slow rate to establish injection and begin walking up rate to
target 60 bpm. If rate cannot be established below 6,000 psi, pump 750 gallons of Hydrochloric Acid. 2) Once rate & pressure are OK proceed with Stage 1 as shown in attached pump schedule 3) Begin Pumping Stage 1 as per the attached pump schedule provided by Frac Company. 4) Max pressure will be 7,000 psi, with kick‐outs set for 6,700 psi. 5) Pump stage as designed. Refer to stage summary sheet for flush volumes and stage specific rate and
pressure limitations (any time shut down is required record ISIP, 5 min, 10 min, and 15 min. If shutdown will be brief 10 and 15 min may be skipped)
6) While stage is pumping, assemble plug and perf assembly to be ready for next WL run. 7) Shut down and record ISIP, 5 min, 10 min and 15min shut in pressure while preparing to swap wells. (If
crew is ready to swap quickly enough, 10 and 15 minute readings may be skipped.) 8) Shut in wellhead at hydraulic valve. 9) Bleed down surface pressure to flow back tanks 10) Function manifold to open pumps up to Shull 8‐25‐9‐60 11) RU WL lubricator and pressure test to ensure good seal 12) Bump up lubricator pressure to last recorded SI pressure plus 100 psi and open well 13) Begin running in hole 14) Once WL is 200 feet in hole begin pumping the next stage on the Shull 8‐25‐9‐60 15) Begin walking pump down rate up as WL approaches 45 degrees to hold constant line Tension. Do not
exceed 12 bpm 16) Once on depth, set plug. As noted on perf sheet, every 5th plug should be a bridge plug. 17) Pull up and shoot next 3 perf clusters. 18) POOH 19) If frac is still pumping on Shull 8‐25 stop at 200 feet and wait until frac as shut down to pull up into
lubricator.
20) Once in lubricator shut in wellhead and bleed down pressure. 21) Break off lubricator and inspect guns to ensure good shot on each gun 22) If all guns demonstrate successful shots, drop ball (no ball drop if bridge plug was set) and close in top
of well. 23) Swap WL back to Shull 8‐25 and frac back to shul 7‐25. 24) Pressure test any broken lines 25) Open WH and begin pumping at 10 bpm until ball seat is observed. 26) Once ball seat is observed, walk rate up to 60 bpm (pumping 750 gallons of acid if needed) and return
to step 5 until all stages are completed. 27) After final stage, record ISIP, 5 min, 10 min and 15min shut in pressure and shut well in. 28) RD frac lines and move lines to Shull 5‐25 to begin next frac 29) RDMO Wireline and prepare for CT drill out after pad is complete 30) Similarly carry out stimulation for other 23 stages
POST FRAC DRILL OUT 30) Get with Greta Hockman (Company Man) to notify oil haulers that the drill out is underway, and estimate
time of flow back. 31) MIRU CTU 32) MU BHA consisting of:
• 2.88” Coil connector • 2.88’ BPV • 2.88” Hydraulic disconnect • 2.88” circulating sub • 2.88” extended reach tool • 2.88’ motor • 3.88” JZ rock bit
33) RIH and begin milling out plugs
34) After each plug pump 5 Bbl sweep 35) After every 5th plug, tag next plug, pump 10 Bbl sweep and short trip back to heel. 36) After final plug, RIH below last perf and pump 20 Bbl sweep. 37) Wait until final sweep is at heel and begin POOH 38) Once at surface, record WH pressure, shut in well and RDMO CTU 39) Open well up to flow back. STAGE REPORT
STIMULATION (FRACTURING) PROCEDURE FOR SLEEVES AND BALL DROP The scope of this work is to prepare the well for stimulation by breaking down & establish an injection rate through the hydraulic port and perform 14 stages of stimulation via the well’s 4‐1/2”, 11.6# liner and the open hole swellable packer completion system, drill out the ports with CTU, flow test the stimulated well, and turn the well to production.
The first stage max rate is 20 bpm until the sleeve is shifted. First ball is NOT in the lateral.
PROCEDURE Perform safety meeting prior to rigging up ANY equipment on location. Discuss the job procedure and objectives with all personnel on location. Document the safety meeting on the report sent to Carrizo. Make note of all potential risks/hazards, and clearly identify an emergency route and emergency vehicle. Also make note of any new or inexperienced personnel on location. Ensure proper Personal Protective Equipment (PPE) is used during the job. Minimums are hard hats, steel toes, and safety glasses. INSTAL FRAC VALVE 1) RU STS and install a BPV. Remove dry hole tree & install Frac Valve. 2) Install 7‐1/16”, 10,000 psi frac stack & test to 8,000 psi. Frac stack should consist of 1 manual lower
master valve, a cross, 2nd manual master valve with goathead, and cap. Remove BPV. The cross should have two wings consisting of 1 ‐ 4” manual valves both sides of the cross. The T for launching balls should be rigged up to provide access on the ground while fracking.
RIG UP FOR STIMULATION 5) Tie the 7” x 9‐5/8” annulus to a flowback tank as a relief line and set up to monitor pressure and hold
1,000 psi. 6) Check transfer lines and transfer pumps to frac tanks from the freshwater storage pit. 7) RU flowback equipment & frac tanks for flowback fluids. Spot equipment so fluid can be trucked out as
the well is flowed back while rigging down Frac Company after the frac.
8) Make sure proppant & chemical supplies can be replenished without interfering with the continuation of the job.
9) Review wellhead hookup and verify sufficient wellhead connections/lines to handle job rates (2 X ID2 X # of lines). Inspect/Confirm ball side 2” line has been laid to ball dropping T to prevent backward flow on ball during drop, and that 4” line has been laid to the wellhead.
10) Test lines to 8,000 psi and inspect all equipment ball/frac side for leaks. 11) Once lines have been primed & tested, run bucket test on blender, hydration unit & back‐ups. 12) Make up fluid sample and confirm sample is cross‐linking at 150 deg F. Record temperatures and pH
and confirm consistency with Fann tests. 13) Obtain sand invoices and confirm that all sand is on location. 14) Review sand and chemical transport schedule with Frac company rep. 15) Conduct pre‐job safety & coordination meeting. Review emergency procedures and designate
emergency vehicles to be used for evacuating any injured personnel. Make sure vendors have sufficient personnel on location or staged nearby to provide relief as needed during the job,(24 – 36 hours). Make sure provisions have been made for crews to be fed and supplied with plenty of drinking water.
16) Caliper all ball sizes. Make sure a backup ball in each size is on location. Store balls in a secure location not accessible to unauthorized personnel on location. Check operation of ball‐dropping system & review ball‐dropping procedure with the Frac company personnel.
PERFORM 14TH STAGE STIMULATION
1) There are no balls in the lateral. Drop the 1.25” ball the morning of the frac before Frac Company is
ready to pump. Allow ball for at least 30 minutes. Do not exceed a rate of 20 bpm until the ball has landed and port 1 is open. At 30 bbls before anticipated impact slow the pumps to 10 bpm. The pressure differential for shifting all ports is approximately 1,876 psi.
2) Establish injection rate with treated fresh water then load the hole with FR water. If pressure and rate allows begin pad. If rate & pressure line out too high to pump proppant, (rate < 20 bpm @ 5,500 psi), discuss plan forward with engineer. Work up to a rate of at least 30 bpm and pump a 50 Bbl sand slug at a 0.25 PPA with the 20/40 sand. If positive results are observed continue pumping slugs throughout the pad. Be sure to leave enough room for pressure increases when the diverter is pumped. Try to avoid shut downs and restarts during the fracture stimulation. If rate & pressure are OK proceed with Stage 1, otherwise, discuss with Operations Supervisor & take additional steps to improve injection.
3) Begin Pumping Stage 1 as per the attached pump schedule provided by Frac Company. Refer to stage summary sheet for flush volumes and stage specific rate and pressure limitations (any time shut down is required record ISIP, 5 min, 10 min, and 15 min. If shutdown will be brief 10 and 15 min may be skipped)
4) Max pressure will be 5,200 psi, with kick‐outs set for 5,000 psi (lowest kick outs starting no higher than 4500 psi)
5) Ball Drop Procedure: i. Load T with next ball during 3 PPA stage. ii. Call stage when the inline densometer reads 0.1 PPA. iii. Immediately cut rate to 40 bpm, and have ball side pressure 500 psi above the frac
side treating pressure iv. When 40 bbls of flush is gone open ball side valve. v. Pump 10 bbls with ball side as quick as possible. vi. When 10 bbls is gone close valve, bleed off pressure ball side. Then check T to
make sure the balls are gone. vii. Once pressure bleeds off walk rate back up to rate in 5 bpm increments staying
under 5,600 psi during flush. viii. When the flush volume is 40 bbls from next stage port lower rate to 20 bpm. ix. When flush volume is 20 bbls from next stage port lower rate down to 12 bpm. x. Monitor pressure to ensure that 1,800 psi under kick out pressure, if not lower
rate to 5 bpm. Look for and note ball action. xi. Break down next formation at same rate ball hit with treated water. xii. Walk pumps back to job rate and begin next stage
6) Ball Procedure when shut down for wellhead drop is required i. Call stage when the inline densometer reads 0.1 PPA. ii. over flush stage by 50 BBL. Shut down and drop next ball from the top. iii. Wait 30 minutes then bring pumps up to 20 BPM for 30 seconds (10 BBL) then
drop rate to 10 BPM to shift sleeve. Walk pumps back to job rate and begin next stage
7) Procedure for final stage i. Call stage when the inline densometer reads 0.1 PPA. ii. Clean up all lines, do not displace gel or chemicals to open top tanks iii. Hold full rate until 20 bbls from flush iv. under flush stage by 1 BBL. Shut down and record ISIP, 5 min, 10 min, and 15 min.
POST FRAC DRILL OUT 8) Get with Greta Hockman (Company man) to notify oil haulers that the drill out is underway, and estimate time of
flowback. 9) MIRU CTU 10) MU BHA consisting of:
a. 2.88” Coil connector b. 2.88’ BPV
c. 2.88” Hydraulic disconnect d. 2.88” circulating sub e. 2.88” extended reach tool f. 2.88’ motor g. 3.88” carbide insert mill
11) RIH and begin milling out seats 12) After each seat pump 5 Bbl sweep 13) After every 5th seat, tag next seat, pump 10 Bbl sweep and short trip back to heel. 14) After final seat, RIH to PBTD and pump 20 Bbl sweep. 15) Wait until final sweep is at heel and begin POOH 16) Once at surface, record WH pressure, shut in well and RDMO CTU 17) Open well up to flowback STAGE REPORT
DRILLING CASING POLICY, BIT SIZE AND MUD POLICY
Detailed AFE (sample AFE) prior to Commencement of drilling for Election and review.
AFE includes both drilling and Completion Costs along with well details.
Top Drive Rig: Extreme 1 with two Mud Pumps (Liner size 6 inch + 10.98 stroke length)
Three stage Casing policy 9.5/8 inch Surface Casing J‐55 36 ppf LTC 7 inch Intermediate Casing N‐80 LTC 23 ppf 4.5 inch Production Casing P‐110 LTC 11.60 ppf either Hanged or Tied Back
FAILURE ANALYSIS OF SUCKER ROD PUMPS IN NIOBRARA JV
Objective:
To carry out study regarding the Failure frequency of Rod pumps and the associated causes which has resulted in their failure.
To carry out root cause analysis for various types of Rod Pump failures
Summarize the failures and possible remedial options
Span of Study:
Rod Pumps in Niobrara Field, where Work over post completion was carried out.
Target: 57 Nos. of wells.
Work over operations involving conversion of Jet Pump into Rod pump and Rod Pump into Gas Lift system not considered
CORROSION MANAGEMENT AND GUIDELINES IN NIOBRARA JV
Guidelines for Interpreting Well Fluid Analysis
Stability Index
The scale covers from ‐3.0 to + 3.0
Generally, we categorize as follows:
0 to ‐.50 Mild/moderate scale/corrosion potential
0 to +.50 Mild/moderate scale/corrosion potential
‐.50 to ‐1.00 Moderate /severe scale/corrosion potential
+.50 to +1.00 Moderate/severe scale corrosion potential
Greater than +1.00 severe scale/corrosion potential
Greater than ‐1.00 Severe scale/corrosion potential
These determinations are made based on the value at 68°F. Keep in mind CaCO3 precipitation increases with
temperature so downhole conditions greatly effect scale formation with increasing depth. Likewise with heater
treaters. Scale formation (for CaCO3) is directly related to the amount of calcium in the water and the bicarb
levels. CaSO4 and BaSO4 potentials are dependent on calcium, barium, and sulfate levels. So we look at multiple
factors when making the above determinations.
Cations
Calcium‐ Levels in excess of 100mg/l can be a problem if the bicarbs are high (in excess of 500 mg/l) and the pH
is above 7.5‐8.0. If the calcium is above 100 mg/l and the sulfate levels are above 150 mg/l then calcium sulfate
is a potential.
Barium‐ Levels in excess of 25 mg/l can be a problem if the sulfate levels are above 100 mg/l. In that case, barium
sulfate could potentially form.
Iron‐ Dissolved iron is an indication (1) of active corrosion in the well or (2) naturally occurring iron in the
formation. We strive to achieve levels of less than 10 mg/l with our chemical inhibitor programs. Iron can also
be present due to microbial contamination. For instance, if sulfate reducing bacteria are present, they feed on
sulfate in the water and produce hydrogen sulfide gas. H2S is corrosive and reacts with iron to form iron sulfide.
Other types of bacteria can also create corrosion problems.
Magnesium‐ Generally does not cause problems by itself.
Sodium‐ Directly related to the salt/salinity level in the water.
Anions
Sulfate‐ Levels above 100 mg/l need to be looked at and compared with calcium, barium, and bicarbs levels.
Bacteria levels are also critical and dependent on sulfate levels.
Chlorides‐ Directly related to salinity.
Bicarbonate‐ Levels above 500 mg/l are suspect depending on the calcium and pH levels.
Carbon dioxide‐ CO2 is corrosive so levels above 15 mg/l are suspect. Depends on the pH and dissolved iron
levels.
Hydrogen Sulfide‐ H2S corrosive and extremely toxic so any detectable level is a concern and requires
investigation to determine where it is coming from. Could be natural or microbially induced.
Total Hardness‐ Is an indication the relative tendency of a water to scale. We typically are alerted if levels exceed
600 mg/l
TDS‐ Is an indication of the relative hardness of the water. Higher levels indicate the water contains high levels
of dissolved metals.
Combination Tendencies
These values estimate the relative presence of each type of scale should scaling occur. All of these guidelines
are relative and somewhat subjective. Predicting what will occur in any individual well is often fairly open ended.
There are literally hundreds of variables in any individual well. It depends on data gleaned from the geochem,
current and past well history (including residual testing), and a fair amount of experience related to how that
well (and neighboring wells) have responded to mechanical and chemical adjustments. It is not an exact science.
