Porosity

Sand grains and particles of carbonate materials that make up sandstone and limestone reservoirs usually never fit together perfectly due to the high degree of irregularity in shape. 

The void space created throughout the beds between grains, called pore space or interstice, is occupied by fluids (liquids and/or gases). 

The porosity of a reservoir rock is defined as that fraction of the bulk volume of the reservoir that is not occupied by the solid framework of the reservoir. The ratio of a volume of void spaces within a rocks to the total bulk volume of that rock is commonly expressed as a percentage ; i.e , all the collective void space is referred to as pore volume so that percent porosity (∅) is calculated as :

Porosity (Ⴔ)= (Volume of void space /total volume of rock) 

Porous sandstone 

The porosity range: 

 The porosity of porous materials could have any value, but the porosity of most sedimentary rocks is generally lower than 50% porosity represents the amount of void space in a rock and is measured as a percentage of the rock volume. 

Porosity is expressed as a percentage on a log. When used in calculations, however, it is important that porosity be expressed in decimal form.

Porosity is determined from conventional core and well log data. Typically, core data are more accurate because porosity is measured directly. Exceptions are unconsolidated sandstone and vuggy /fractured reservoirs . In unconsolidated sandstones , well log values of porosity are considered to be more accurate than disturbed core samples . 

In formations with vugs and fracture, it is challenging to obtain a representative core sample. The recommended approach is to compare core and log porosities at the same depth for each well that has been both cored and logged. The log porosities are adjusted to match the core data either by adjusting the inputs into the log calibration . If there are insufficient data to match core and log data directly, then the overall average core porosity can be compared with overall average log porosity . Some judgment is required to ensure that an appropriate comparison is made. For example is not valid to calibrate log data coming from one rock type (e.g., shaly sandstone ) 

Porosity is one of the more reliable reservoir measurements. Once an average porosity is determined, it is not recommended to adjust the average porosity by more than 0.01-0.03 .One exception to this rule of thumb is highly heterogeneous reservoirs with limited porosity data . Generally, porosity is a decreasing function of depth.  

In  a sandstone , this value is typically  much lower due to cementation and compaction . 

In a carbonate , it is possible to greatly exceed the theoretical  maximum porosity . Tis may be  achieved if the carbonate is highly fractured along with vuggy porosity .  

It is often said that porosity is: 

- Low if Ⴔ <5%

- Poor if 5% <Ⴔ <10%

- Moderate if 10% Ⴔ <20%

- Good if 20% <Ⴔ <30%

- Excellent if Ⴔ> 30%

Effective vs . noneffective porosity 

FACTORS GOVERNING THE MAGNITUDE OF POROSITY : 

The porosities of petroleum reservoirs range from 5% to 40% but most frequently are between 10% and 20%. The factors governing the magnitude of porosity in clastic sediments are:

a)      Uniformity of grain size (Well Sorted Rock ) :

Uniformity or sorting is the gradation of grains. If small particles of silt or clay are mixed with larger sand grains, the effective (intercommunicating) porosity will be considerably reduced. These reservoirs are referred to as dirty or shaly. Sorting depends on at least four major factors: size range of material, type of deposition, current characteristics, and the duration of the sedimentary process.

Very well sorted 

Poorly sorted 

Porosity relation  to arrangement  and shape  of rock  grains 

  b)      Degree of cementation or consolidation:

The highly cemented sand stones have low porosities, whereas the soft, unconsolidated rocks have high porosities. Cementation takes place both at the time of lithification and during rock alteration by circulating groundwater. The process is essentially that of filling void spaces with mineral material, which reduce porosity.

Cementing materials include: calcium carbonate, magnesium carbonate, iron carbonate, iron sulfides, limonite, hematite, dolomite calcium sulphate, clays, and many other materials including any combination of these materials.

Effect of cementation on porosity 

        c)   Amount of compaction during and after deposition:

c)   The amount of porosity is principally caused by the arrangement and shape of the rock grains, the mixing of grains of different sizes and shapes, and the amount of cementing material present

      Compaction tends to lose voids and squeeze fluid out to bring the mineral particles close together, especially the finer-grained sedimentary rocks. This expulsion of fluids by compaction at an increased temperature is the basic mechanism for primary migration of petroleum from the source to reservoir rocks. Whereas compaction is an important lithifying process in claystones, shales, and fine-grained carbonate rocks, it is negligible in closely packed sandstones or conglomerates.

Generally, porosity is lower in deeper, older rocks, but exceptions to this basic trend are common. Many carbonate rocks show little evidence of physical compaction.

Sedimentation process : Layer A is compacted by layer B 

d)      Grain  Packing:

With increasing overburden pressure, poorly sorted angular sand grains show a progressive change from random packing to a closer packing. Some crushing and plastic deformation of the sand particles occur.

Grain packing and its effect on porosity 

ENGINEERING CLASSIFICATION OF POROSITY:

During sedimentation and lithification, some of the pore spaces initially developed became isolated from the other pore spaces by various diagenetic and catagenetic processes such as cementation and compaction. Thus, many of the pores will be interconnected, whereas others will be completely isolated. This leads to two distinct categories of porosity, namely, total (absolute) and effective, depending upon which pore spaces are measured in determining the volume of these pore spaces. The difference between the total and effective porosities is the isolated or non-effective porosity.

Absolute porosities is the ratio of the total void space in the sample to the bulk volume of that sample, regardless of whether or not those void spaces are interconnected. A rock may have considerable absolute porosity and yet have no fluid conductivity for lack of pore interconnections. Examples of this are lava, pumice stone, and other rocks with vesicular porosity.

Total porosity is all void space in a rock and matrix whether effective or noneffective.

Effective porosity is affected by a number of lithological factors including the type, content, and hydration of the clays present in the rock, the heterogeneity of grain sizes, the packing and cementation of the grains, and any weathering and leaching that may have affected the rock. Many of the pores may be dead-ends with only one entry to the main pore channel system. Depending on wettability, these dead-end pores may be filled with water or oil, which are irreducible fluids. Experimental techniques for measuring porosity must take these facts into consideration. In order to recover oil and gas from reservoirs, the hydrocarbons must flow several hundred feet through the pore channels in the rock before they reach the producing wellbore. If the petroleum occupies non-connected void spaces, it cannot be produced and is of little interest to the petroleum engineer. Therefore, effective porosity is the value used in all reservoir engineering calculations. It represents the ration of the interconnected pore space to the total bulk volume. Other terminology such as secondary porosity, water-filled porosity, vuggy porosity, and fracture porosity.   

Effective porosity is the interconnected pore volume available to free fluids. Connected porosity where void space has flow through potential is called effective porosity. Noneffective porosity is isolated. Summation of effective and noneffective porosity produces total porosity, which represents all of the void space in a rock. 

GEOLOGICAL CLASSIFICATION OF POROSITY

As sediments were deposited in geologically ancient seas, the first fluid that filled pore spaces in sand beds was seawater, generally referred to as connate water. A common method of classlfying porosity of petroleum reservoirs is based on whether pore spaces in which oil and gas are found originated when the sand beds were laid down (primary or matrix porosity), or if they were formed through subsequent diagenesis (e.g., dolomitization in carbonate rocks), catagenesis, earth stresses, and solution by water flowing through the rock (secondary or induced porosity).

The following general classification of porosity, adapted from Ellison, is based on the time of origin, mode of origin, and distribution relationships of pores spaces.

Pore space in rocks at the time of deposition is original, or primary porosity. It is usually a function of the amount of space between rock-forming grains. Original porosity is reduced by compaction and groundwater –related diagenetic processes.

Groundwater solution, recrystallization, and fracturing cause secondary porosity, which develops after sediments are deposited.

Primary Porosity:	Secondary Porosity Secondary porosity:	Fracture porosity
Amount of pore space present in the sediment at the time of deposition, or formed during sedimentation.  It is usually a function of the amount of space between rock-forming grains.        1. Intercrystalline: voids between cleavage planes of crystals, voids between individual crystals, and voids in crystal lattices. Many of these voids are sub-capillary, i.e., pores less than 0.002 mm in diameter. The porosity found in crystal lattices and between mud-sized particles has been called “micro-porosity” by Pittma. Unusually high recovery of water in some productive carbonate reservoirs may be due to the presence of large quantities of microporosity . 2. Intergranular or interparticle: voids between grains, i.e., interstitial voids of all kinds in all types of rocks. These openings range from sub-capillary through super-capillary size (voids greater than 0.5 mm in diameter). 3. Beddingplanes: voids of many varieties are concentrated parallel to bedding planes. The larger geometry of many petroleum reservoirs is controlled by such bedding planes. Differences of sediments deposited, of particle sizes and arrangements, and of the environments of deposition are causes of bedding plane voids. 4. Miscellaneous sedimentary voids: (1) voids resulting from the accumulation of detrital fragments of fossils, (2) voids resulting from the packing of oolites, (3) vuggy and cavernous voids of irregular and variable sizes for at the time of deposition, and (4) voids created by living organisms at the time of deposition. Primary porosity is dominant in clastic-also called detrital or fragmental-sedimentary rockssuch as sandstones, conglomerates, and certain oolitic limestones	Post depositional porosity.  Such porosity results from groundwater dissolution, recrystallization and fracturing. It is the result of geological processes (diagenesis and catagenesis) after the deposition of sediment. The magnitude, shape, size, and interconnection of the pores may have no direct relation to the form of original sedimentary particles. Induced porosity can be subdivided into three groups based on the most dominant geological process 1. Solutionporosity: channels due to the solution of rocks by circulating warm or hot solutions; openings caused by weathering, such as enlarged joints and solution caverns; and voids caused by organisms and later enlarged by solution. 2. Dolomitization: a process by which limestone is transformed into dolomite according to the following chemical reaction: limestone dolomite 2CaCo~ + Mg2+ -+ CaMg(Co3) + Ca2+ (3.2) Some carbonates are almost pure limestones, and if the circulating pore water contains significant amounts of magnesium cation, the calcium in the rock can be exchanged for magnesium in the solution. Because the ionic volume of magnesium is considerably smaller than that of the calcium, which it replaces, the resulting dolomite will have greater porosity. Complete replacement of calcium by magnesium can result in a 12-13% increase in porosity . 3. Fracture porosity: openings created by structural failure of the reservoir rocks under tension caused by tectonic activities such as folding and faulting. These openings include joints, fissures, and fractures. In some reservoir rocks, such as the Ellenburger carbonate fields of West Texas, fracture porosity is important. Porosity due to fractures alone in the carbonates usually does not exceed 1% [7]. 4. Miscellaneous secondary voids: (1) saddle reefs, which are openings at the crests of closely folded narrow anticlines; (2) pitches and flats, which are openings formed by the parting of beds under gentle slumping; and (3) voids caused by submarine slide breccias and conglomerates resulting from gravity movement of seafloor material after partial lithification. In carbonate reservoirs, secondary porosity is much more important than primary porosity: Dolomites comprise nearly 80% of North American hydrocarbon reservoirs.  However, it is important to emphasize that both types of porosity often occur in the same reservoir rock.	Results from the presence of openings produced by the breaking or shattering of a rock.  All rock types are affected by fracturing and a rocks composition will determine how brittle the rock is and how much fracturing will occur.   The two basic types of fractures include natural tectonically related fractures and hydraulically induced fractures.  Hydraulic fracturing is a method of stimulating production by inducing fractures and fissures in the formation by injecting fluids into the reservoir rock at pressures which exceed the strength of the rock.  Hydraulic fracturing can tremendously increase the effective porosity and permeability of a formation.

VISUAL DESCRIPTION OF POROSITY IN CARBONATE ROCKS : 

The role played by the visual description of pore space in carbonate rocks has changed considerably since the development of a method for classifying carbonate reservoir rocks in 1952 by Archie.

The development of well logging technology has provided the petroleum industry with effective and direct methods to measure the in-situ porosity of a formation.

The visual description of the pore geometry, however, is still needed to estimate the effects of

•  The grain size;
•  The amount of inter-particle porosity;
•  The amount of unconnected vugs;
•  The presence of fractures and cavities;

-         The presence or absence of connected vugs on the porosity-permeability relationship and other petrophysical parameters of naturally fractured reservoirs.

  Lucia presented field classification of carbonate rock pore space based on the visual description of petrophysical parameters of a large number of samples. He also discussed basic geological characteristics necessary for the visual estimation of particle size and recognition of interparticle pore space, and connected and unconnected vugs. Lucia proposed a field classification of carbonate porosity as follows:

• For fine particle size (d, less than 20 pm), the displacement pressure, PD, is greater than 70 psia;
• For medium particle size (20 .c d, .c 100 pm), the PD is in the range of 15-70 psia;
• For large grains (d, > 100 pm), the displacement pressure is less than 15 psia. The term PD is the extrapolated displacement pressure, which is determined from the mercury capillary-pressure curves , shows the relationship between PD and the average grain size as a function of the inter-granular porosity for non-vuggy rocks with permeability greater than 0.1 mD. This relation-ship is the basis for dividing particle size into the three groups.

QUANTITATIVE USE OF POROSITY : 

Calculating reservoir oil content  the initial oil-in-place, the initial gas-in-place, and The initial gas deviation (also called compressibility)

Core-log porosity integration: 

• If we have core data, we overlay it on the log porosity data.
• We double check that both logs are on depth.
•  If the core porosity is matched with log porosity, then our parameters are optimal.
•  If the core data is not matched with the porosity from log, then we need to do corrections for the porosity from log.
• Either test the parameter or cross plot the porosity from log with the one from log. In general , a  regression line shows  that the log porosity is 0.01 less than the core porosity, which may be due to slight different in Matrix density or fluid density.

 

Fluid Contacts Definition

 

At the time of discovery, reservoir fluids are in hydraulic equilibrium, and they are vertically distributed  according to their density at reservoir pressure and temperature .The interface  between these fluids is horizontal and therefore , if the reservoir is hydraulically connected , all the wells will encounter these fluid  contacts  at the same depth . As a consequence, if different wells drilled in the same reservoir  encounter fluid contacts at different depths , the reservoir  is likely to be compartmentalized .

It should  be noted  that the existence of a common fluid contact in all the wells drilled during the appraisal phase does not  guarantee  in itself  reservoir  continuity . In some cases , barriers  to fluid flow  may have  been generated  only after the hydrocarbon migration phase , as a consequence   of  diagenetic  effects  relate  to circulation  of fluids in  the reservoir . In  this case , reservoir barriers  are normally detected  only after  the beginning of the exploitation , observing  for example  different rises of the fluid contacts in different blocks , as  a result of  reservoir fluids withdrawal .

In the majority  of cases , however , the general rule holds  and differences in the contacts depth can be interpreted as evidences of  a degree of reservoir  compartmentalization .   

Several types of data can be used  to locate fluid contacts , from wireline  logs , to routine  core analysis , to pressure measurements .Without  going into  further  detail on this basic   issue , it should be  appreciated that WFT  (Wireline  Formation Tester )  pressure measurements   are  one of the most effective  way  to identify  fluid contacts , at any  stage  of field life .

The precise knowledge of the contact of fluids (gas-oil, gas-water or oil-water) makes it possible to define the useful height of the reservoir as well as the surface of the reservoir.

Methods for determining fluid contact:

·         Resistivity log

·         MDT -Modular Formation Dynamics Tester

·         DST- Drill stem Testing

·         Sw Cut off evaluation

·         Structural closure:

WOC  determined by  SW evaluation

 

WOC  determined by Resistivity log 

 

WOC  determined by  MDT

WOC  determined by DST 

Spill point in the absence of WOC, ODT and WUT, the surface of the deposit can be approximated by the curve of structural closure (Spill point).This assumes a load factor of the structure of 100% (Optimistic surface and reserves).

Spilling  Point (La fermeture Structurale ) 

The ODT is the base of the hydrocarbon column that does not rest directly on an aquifer. It can be taken as a pessimistic interval  of water for estimating the surface area of the deposit (and the useful height).In a well, there is no evidence of the existence or absence of hydrocarbons lower than this base. ODT as a "pessimistic interval  of water".

Example: HC column resting on a compact or clay level

ODT Contact 

The WUT is the highest recognized water grade in a well. Also, nothing proves the existence or non-existence of water higher than this level .

The WUT can be taken as an optimistic body of water to estimate reserves in the absence of an obvious body of water. The WUT as an optimistic 'water interval '

WUT Contact 

 

 

Imaging Techniques for Geological Modeling

 Maps and Cross Sections : 

Most reservoir maps in the world use m.s.l.  as the reference. Depths of the layer increases away from 

the crest of the structure.

The reference is needed because the drilling rig can be on top of  a mountain or an offshore platform.

 In each case the measured depth of the same layer is different as the drilling reference is different.

Piratically any type of geologic data  can be represented on a map .Some of the  most useful maps are 

those that present clear pictures  of the distribution of geologic parameters .

A geologic  map is  an  example of this because  it shows the distribution of  individual rock 

formations   over the area of the map . 

Contour maps can illustrate thickness , facies , percentages , topography , and structure .They  show 

variations that are useful in interpreting the complete geology of an area or individual characteristics 

within the entire data structure . 

Contour  Maps : 

Data upon which numerical values can be placed  can be contoured , since contour  lines connect 

points  of equal value .Contour maps are important interpretive aids and can represent anything  from 

sequential geologic events to absolute values of individual parameters within single rock units .

1. Contour interval should adequately represent the data .Too large an interval overlooks some of the data and too small an interval clutters the map . 
2. Contour lines should honor the data and be properly spaced relative to them .
3. Contour lines should  be drawn smoothly and as parallel to each others as the data will allow .
4. Contour lines should never cross .Crossing contour lines are an impossibility. 
5. Contour lines  should be close together where gradients are steep and farther apart where gradients are shallow .
6. Contour lines  should be labeled . 

Geological Maps :

Geological maps can include as much or as little data as desired .Usually they include  formations and 

their contacts and the most prominent faults .However , geologic maps can also include topographic  

and structural  contours , as well as structural features .

Most geologic maps are colored .But data also can be represented by the use of symbols or different 

tones of gray . Geographic features are essential for purposes of location .

Cross Sections :

Structural , stratigraphic  and topographic information  can be portrayed on cross-sections  that

 reproduce horizontally represented map information in vertical section .

Maps represent information  in the plan  view and provide a graphic view of distribution .Cross-

sections present the same information in the vertical  view and illustrate vertical relationships such as 

depth , thickness , superposition , and lateral and vertical changes of geologic features .

Raw data for cross-sections  come from stratigraphic sections , structural data , well sample logs , 

cores , electric logs  , and structural , stratigraphic and topographic  maps . Datum for the cross-

sections is sea level .

Formation Evaluation & Objectives

Formation Evaluation is the systematic way of recording  the information required to evaluate 

formation Characteristics of a well being drilled .

Objective: To establish the existence of producible hydrocarbon reservoirs (oil & gas).

Type of information obtained from formation Evaluation in Petroleum Geology :

·         Presence of Hydrocarbon

·         Pore pressure analysis

·         Caliper for hole size

·         Core and fluid samples

·         Cuttings

·         Reservoir characteristics

·         Formation strength

Methods to obtain information :

·         Wireline logging : GR , Laterolog , Litho-density tool ,Neutron tool,

·         Logging while drilling

·         Coring

·         Mud logging

·         Well testing

Basic logging Tools measurements:

1.   Wireline Logging tools : 

Electrical Logs:  measure the electrical properties of the 

Example of a Gamma Ray Log

formation along with the formation fluids. 

Gamma Ray Logs: measure the natural radioactivity of the 

formation. It reflects the shale content of 

the formation.    

        GR Logs are used as:

• Correlation tool
• Shale indicator
• Shoulder bed delineation
• Differentiate reservoir rocks from non-reservoir rocks.

Spontaneous -Potential Log: measures the potential 

difference in milli-volts between an electrode in 

the borehole and a grounded electrode at surface. 

The SP is  a passive measurement of very small electrical 

voltages resulting from electrical currents in 

the borehole caused by the differences in the salinities 

(resistivity) of the formation connate  water 

(R_w)  and the drilling mud filtrate (R_mf) , and by the presence 

of ion selective  shale beds .

The tool can be run :
Open hole	centered
Cased hole	eccentered
In a borehole fluid of :
Water or water –based mud
Logging speed : the logging speed is constrained by other measurements in the toolstring
Comments : Usually run with induction logs and old electric logs , the SP can also be run with laterologs , sonic, micrologs , dipmeters , and sidewall cores .There usually is no separate SP tool .

Spontaneous Polarization

Density Logs LITHO-DENSITY TOOL (LDT): measure electron density of the formation which is 

related to formation density. The density value is used to determine the porosity of the formation LDT 

measurement are made by emitting medium energy gamma-rays into the formation and measuring the 

number, and the energy of the gamma-rays returning to the tool.

Neutron logs:  measure hydrogen index of the formation. This log is used primarily for delineation of 

porous formations and determination of porosity.

A combination of neutron log with one or more other porosity logs provides more accurate porosity 

values and lithology identification.

Laterolog Tools: require current to be passed through the borehole and into the formation in order to 

measure fluid resistivity. It consists of resistivity and conductivity tool.

-          RESISTIVITY TOOL :  Send current into the formation and measures the ease of electrical 

flow through the formation.

-          CONDUCTIVITY TOOL: Induces an electric current into the formation and measures how 

large the formation is Rt is measured by both tools and is used to calculate hydrocarbon reserves.

Sonic Logs: measure the elastic or (sound) wave properties of the formation. It records interval transit 

time (dt) in us/ft. It is the time taken for a sound pulse emitted from a transmitter to transverse 1 ft of 

formation.The interval transit time for a  given formation depends on its  lithology and porosity. When 

the lithology is known, sonic log is a useful porosity tool

Caliper Logs: measure the size or geometry of the hole.

2.   LOGGING WHILE DRILLING (LWD):

LOGGING WHILE DRILLING (LWD) is a method used to perform formation evaluation similar to 

electric wireline logging .However , the difference  between the tow is that the the log results from   

LWD   are obtained Real –Time while drilling the hole section .  

3.   CORING :

Is a process used to recover cylindrical rock sample from the wellbore by using specific coring tools . 

The main objective of taking core is to gain  an understanding of the composition of the reservoir rock,

physical rock properties , inter-reservoir seals  and the reservoir pore system.

-        Advantage of coring - more accurate and reliable data of porosity and permeability.

-         Disadvantage - additional cost required for the extra BHA trip to cut the core, late information in place 

du   to the core need to be analyzed and studied in laboratory.

-        Coring is performed  between drilling operations once the formation for which a core is required has  

       been identified on the mud log or LWD log , the drilling assembly is pulled out of  hole .

-        A special assembly   is run on drill pipe  comprising  of a core bit and core barrel.

-        The core is cut free and prevented from falling out of the barrel by a core catcher while being brought 

up to surface.

Sample of Core 

3.   MUD LOGGING :

Is the recording of information derived from examination and analysis of formation cuttings  

circulated  out of the hole for Oil shows and Gas reading through mud circulation?

    Cuttings are taken across the full width of the shakers to be representative of the interval drilled.

   Cutting logs shall be known at all times. Lithological analysis of the cuttings normally is performed 

  on  the washed samples indicating fluorescence after treatment with solvents to indicate presence of hydrocarbons.

4.   WELL TESTING :

The main objectives of running a well test are to make an indirect determination of the reservoir 

physical characteristics and to get physical measurement of well performance and representative fluid 

samples .

•          It is performed after the presence of hydrocarbon is confirmed from the logs.

•          Well test results are very important for development plan.

 By performing a well test, we gather information on:

1-      PERMEABILITY

2-      SKIN

3-      RESERVOIR MODEL

4-      FLOW EFFICIENCY

5-      FLOW RATE

6-      GOR

7-    FLUID COMPOSITION

8 -   PVT SAMPLES

 

 

Uses of Logs by variety of Petroleum People .

 

             A set of logs run on a well  usually mean different things to different people .                 In this blog , we examine the questions asked –and/or answers sought by variety of petroleum people .

The Geophysicist :

•  Are the tops where you predicted ?
•  Are the potential zones porous as you have assumed from seismic data ?
• What does a synthetic seismic section show ?

The Geologist :

• What depths are the formation tops ?
• Is the environment suitable for accumulation of hydrocarbons?
• Is there evidence of hydrocarbons in this well ?
• What type of hydrocarbons ?
• Are hydrocarbons present in commercial quantities ?
• How a well is it ?
•  What are the reserves ?
• Could the formation be commercial in an offset well ?

The Drilling Engineer :

• What is the hole volume for cementing ?
•  Are there any key seats of severe doglegs in the well ,
• Where can you get a good packer seat for testing ?
• Where is the best place to set a whipstock ?

 

The Reservoir Engineer :

• How thick is the pay zone ? 
• How homogeneous is the section ?
• What is the volume of hydrocarbons per cubic meter ?
• Will the well pay-out?
• How long will it take?

The Production Engineer :

•  Where should the well be completed (in what  zone(s))?
• What kind of production rate can be expected ?
•  Will there be any water production ?
•  How should the well be completed ?
• Is the potential pay zone hydraulically isolated ?
• Will the well require any stimulation ?
• What kind of stimulation would be best ?