Figure 1: Granted patents in 2011

The inventions are mostly in production and operation activities (Figure 2). Schlumberger contributes the most with 173 granted patents span from production management, measuring flowrate, cable, fluid filter, well treatments to ICD. Major oil companies only have 66 patents in the activity.

Figure 2: Research activities in 2011

Schlumberger as a logging company have been done research mostly on reservoir evaluation and engineering (188 granted patents). Forty five patents are in the Logging, formation  and reservoir evaluation such as logging tool, induction resistivity tool, formation evaluation system and integrated reservoir optimization. Besides, people in SLB research center are also loaded with many novel ideas in drilling and completion activities such as steerable drilling system and completing a multiple zone well.

Baker hughes and Halliburton look similar to Schlumberger. Their research activities are mostly on drilling, completion, production and operation.

Contrary to service companies, major oil companies are busy on petrochemical research activities. More than 35% of the research that turn out to be granted patent are on petrochemical inventions such as lubricating oil compositions and low sulphur alkylate gasoline fuel. Shell got 60 granted patents on petrochemical inventions out of total 162 patents.

1. MICROBIAL STIMULATION

Bacteria can live in harsh condition such as in oil reservoir. Bacteria have very simple cellular structure (FIGURE 1)that helps it to stay dormant in reservoir pore. By improving the environment condition, bacteria can “wake-up” from dormant state to living micro-organism.  In very satisfaction environment, bacteria can grow by cell division and double in number as quickly as 9.8 minutes. Dormant anaerobic bacteria in the reservoir will stay dormant in the produced water. By sampling the water and analyzing in the lab, the bacteria can be identified and then the resource substances can be formulated to grow the bacteria. If there are no suitable bacteria in the reservoir to disclog oil, bacteria that will living mutually with residence bacteria will be injected from surface within injected water along with nutrients.

FIGURE 1: Bacteria with simple cellular structure

Microbe has certain criteria to grow. Generally, microbe can live below 80 ᵒC and 2400 psi. Salinity and pH also affect the optimum condition to grow microbe.

The substances that will unclog the oil and make it more movable are bacteria secretion. The secretion acts similar to chemical surfactant that influences surface tension oil-water and oil-rock. In very favorable condition, bacteria will multiply faster and produce more secretion. Phosphate must be supplied as part of bacteria nutrition beside of oil. As one cell organism, optimum thermodynamic activity in the form of oxidizing – reducing reaction will promote faster multiplying. Anaerobic bacteria such as sulphate reducing bacteria (SRB), nitrate reducing bacteria (NRB), iron reducing bacteria (IRB) and acetogenic bacteria will act as electron donor while Nitrate that is supplied along with injected water will acts as electron acceptor. The inventor believe vitamins such as  B12, biotin, folic acid, nicotinic acid, aminobenzoic acid, calcium pantothenate, pyridoxine HCl, riboflavin , thiamine,thioctic acid will promote better condition for bacteria to multiply.

Anaerobic bacteria that eat oil are more favorable than that does not eat oil. By eating oil, nutrient supplied along with injected water will be less. The rate and concentration of nutrients and vitamins must be determined in the lab. The inventor suggests the rate between 0.1 and 15 m/day and concentration between 1 and 1000 m g/l. The inventor also specifically avoids the use of oxygen.

2. HEAT-VIBRATION STIMULATION

Reacting two chemical substances in the reservoir is the idea. The reaction will produce micro-explosion (vibration) and heat. The chemical substances must endure at reservoir P/T before reaction. Spacer such as water, brine or carbon tetrachloride, is injected between chemical substances to avoid premature reactions.

The main chemical substance in the invention is pentaethylene hexamine -3CO (PEH-3CO, FIGURE 2). PEH-3CO (polymer) reacted with acid will produce micro-explosion, heat and CO2. The following is the stoichiometry of PEH-3CO / acid system:

PEH-3CO + nHX (acid) —-> PEH Hn + Xn- + 3CO2 + heat

FIGURE 2: PEH-3CO

Gas CO2 will increase pressure. Heat will decrease oil viscosity and vibration of micro-explosion will release trapped oil. Overall, the stimulation will increase oil recovery.

The vibration intensity and duration of micro-explosion can be controlled by the type and structure of the chemical substances used. The type and structure of the chemical substances must be evaluated in the lab. Compatibility check must be run to avoid precipitation in the reservoir due to negative ion Xn- since formation water contains several salts.

The target reservoir contains 31.93 MMSTB of oil with 10% oil recovery after 27 years of production.  The gross pay of the reservoir which is mostly shaly limestone is 45 m average.  The primary drive mechanism in the reservoir is fluid expansion drive (solution gas drive) with very low water influx. Production from the reservoir is characterized by high initial rate with high rate decline. Currently, mostly wells producing from the reservoir suffer water blocking where water is encroaching the wells and is saturating around the wellbore.

The oil has 35 API gravity with 211 scf/stb cumulative GOR (black oil). Initially, the oil moved 2.1 times slower than water. At pressure around 900 psi, the oil moved more slower and  was left by water which saturated the vicinity of the wellbores.  The wellbores have then suffer high water cut production (more than 95%) until economic limit is reached. However, when a new well is drilled in new location (such as only 15 meters away, well C1 on Figure 5), the  well produces fluid with water cut much lower (60%) even the perforation is lower than the 95% water cut wells (well B and B1 on Figure 5). This indicates that much oil which cannot move to water-blocked wells is still left between wells .

Water flooding model

The model is based on frontal displacement theory which was developed by Buckley and Leverett in 1942. The fractional flow equation and frontal advance equation in the theory are applied for radial flow model. Both equations are presented here:

Fractional flow equation:

Frontal advance equation:

To solve fractional flow equation, data permeability vs water saturation is required from core analysis (Figure 1). For simplifying, capillary pressure effect is neglected.  Both graphs of fractional flow equation and frontal advance equation are plotted on the same scale (Figure 2). The effect of injection is evaluated in three phases:

1. Phase 1: Solving water blocking around wellbore of producers, no noticeable water cut change in the producers.

2. Phase 2: Stabilizing water cut, water cut in the producers gradually decrease.

3. Phase 3: Stabilized water cut, water cut in the producers relatively constant until water breakthrough.

Phase 1 will be last for 7.6 days without noticeable water cut change in the producers. Water cut will gradually decrease to 73%. This production profile will be stable until water breakthrough or 314 days. Figure 3 shows cross section front movement and Figure 4 shows radial front movement.

Figure 1: Permeability vs water saturation

Figure 2: Solving fractional flow equation and frontal advance equation

Figure 3: Cross section front movement

Figure 4: Radial front movement

Effect of well A (injector)

Refer to top structure map on Figure 5. The structure is relatively plate with around 250 m of distance between wells. Well A have been injected for quite long. Total 261 Mbbl of water have been injected since 2009 with average rate of 575 bwpd. The injection phases in well A1 and A3 is not distinguishable. However, based on the model above, phase 2 had been finished in 30.5 days or after 101 Mbbl (5.1% PV) of water injected and phase 3 have remained until water breakthrough reached or after injecting 1039 Mbbl (53.1 % PV) of water. Rate declines on Figure 6 and Figure 7 show clearly the effect of injection in well A where both rate declines are negative. Water cut of both wells tend to decrease to 73% and oil productions keep increasing. Noncontinuous injection to well A due to unreliable production facility results in low horizontal sweeping efficiency. “Stop and go” situation during injection with low injection rate (575 bwpd average) has allowed water to escape to aquifer naturally and leaves oil on top building water-oil layer in the reservoir.  Continuous injection with high rate (2000 bwpd) will solve the problem.

Figure 5: Top structure

Figure 6: Rate decline well A1

Figure 7: Rate decline well A3

Estimated production

Current field production is 270 bopd with only well A as injector. By converting well B, C and D into injection well, the field will loss 30 bopd. After 30.5 days, the production will climb up to 560 bopd where every injection cluster contribute between 50 and 125 bopd each.

Future development

After injecting water for 314 days or 53.1% PV, all producers will water-out. Continuing water injection will uneconomically visible. However, from the previous project, pay continuity had been concluded. Moreover, well A as injector connect to well A1 and well A3 as previously discussed. IOR or EOR is the next step for exploiting the reservoir. By adjusting the completion of wells to make the injector closer to producers by means of horizontal radial drilling will improve oil recovery (IOR). Adding chemical such as surfactant into injected water will enhance oil recovery (EOR). Injecting water+chemical immediately after 15% PV of water injected will decrease pumping cost and processing costs.

In current patent by BP Exploration Operating Company Ltd.,  water with certain ionic concentration will give better performance in case of horizontal and vertical sweep. It is concluded that 500 to 5000 ppm of certain ionic concentration will increase oil recovery. To achieve such concentration with certain ionic concentration, a reverse osmosis plant and high salinity source water are required. The plant will need at least 0.1 MPa of pressure higher than osmotic pressure of the membrane to get reverse osmosis effects. To fulfill 2000 bwpd injection rate, around 30 square meters of osmotic membrane are needed.

Casing is run subsequently to secure the hole wall from collapsing, steel casings are used mostly. Then cement is placed between casing and borehole to isolate productive zones hydraulically. The casing and cement are perforated at productive zone to allow reservoir fluid flowing into the well.

In horizontal well, slotted liner is more preferable than casing tubular since the leg (horizontal section) is only connected to one reservoir . The slotted liner is required to prevent the borehole from collapsing and the slots are design to prevent sands flowing into well.

During the well life, fluid saturation around the well or between wells is changing. Re-running electrical logging tools to measure fluid saturation are impossible. Pulsed neutron logging  which measures carbon-oxygen ratios is run to assess the changing. But this method has shallow depth of investigation and low accuracy in low porosity reservoir.

The question comes up whether there is any possibility to pass electric signal (EM signal) through slots and measure reservoir properties as done in open hole logging. The answer is yes. Now, the challenge is to make the slot through casing and run suitable electric logging tools.

The inventors protect their idea in the form of method (procedures) and system (tools).  Making the opening (slots) is a very important part of the method and the system. The slots can be pre-installed on the casing before running or made using mill-cutter, perforating gun, sandblast cutter or other means. At least one transmitter and one receiver is required, more is better.

Figure 1: Pre-installed slots on casing

Figure 1 shows pre-installed slots on casing. The insulator which is made from material that transmits EM radiation covers the slots to provide isolation during cementing.

Figure 2: Logging in water coning well

Re-logging producing wells can give information about fluid distribution behind casing or between wells. Re-logging periodically to monitor the resevoir will give information any changing during the life of the well. Sometimes, in high water cut wells, oil is still unproduced due to water saturated zone. Figure 2 shows the logging result. Instruments B and C gives difference results for deep and shallow surveys which conclude oil left due to water blocking around well. Immediate remediation can be taken accurately to allow oil flowing into the well.

FIGURE 1: WC peak-up indicate bypassed oil

Peripheral water flooding will require voluminous water to increase reservoir pressure. The water will not drive oil efficiently since most of the water will escape into aquifer instead of pushing the oil into producers.

By assuming the reservoir isotropic, patterned water flooding will increase areal sweep efficiency significantly.  The pattern might 5 spot, 7 spot, or line drive. Simulation will help to assess the best pattern for flooding.

In heterogenic reservoir, the water flooding performance could be very low with early water breakthrough and bypassed oil. Water will preferentially flow through larger pore spaces or micro fractures especially in carbonate reservoir leaving oil in smaller pore spaces. By changing interfacial tension of oil to rock, some oil will easier to release from small pore spaces. Surfactant can help improving the performance of water flooding.

Water is a good pusher to displace oil horizontally but poor vertically due to lower vertical permeability. Gas is more superior in vertical displacement aided by gravity but poor for horizontal displacement due to low viscosity of the gas such that gas will finger through oil. Water can control this fingering so that flooding combination of water and gas will increase oil recovery. Gas will displace oil from small pore spaces to larger pore spaces where water can easily push it into producers. Problem arises over certain distance where gas and water are segregated gravitily. Gas will build layer at the upper of the reservoir and fingering into producers. In other hand, water escape to the bottom of the reservoir and channeling through micro fractures. It is obvious that mixed flow of water and gas is more effective and less fluid loss.

FIGURE 2: Improving vertical sweep

The patent filed under Herbert L. Stone resolve the segregation problems by mixing water and gas in the reservoir.  Water is injected at the upper part of the reservoir and gas is at the bottom of the reservoir preferably slightly below WOC (FIGURE 2). The mixing ratio of water to gas is simulated such that gas mobility is as small as possible. Water injection at the upper of reservoir can be stopped for a while for allowing water and gas mixed. Water and gas injection rate, duration of water injection interruption will determine the area of mixed flow zone. The bigger the mixed flow zone, the better is the sweep efficiency horizontally and vertically. Higher gas injection rate will build bigger mixed flow zone. It is desirable to inject gas with pressure close to reservoir fracturing pressure.

FIGURE 3: Area influenced by vertical well vs horizontal well

Horizontal wells can deliver fluid with higher rate into reservoir if compared to vertical wells. In thin reservoir, vertical wells will have a low maximum injection rate to avoid fracturing. Denser well spacing will be required to achieve higher oil recovery. For thin reservoir, horizontal wells are more desirable to deliver high gas rate and bigger mixed flow zone so that denser well spacing is not required. FIGURE 3 shows the comparison of area influenced by vertical well and by horizontal well. For the same reservoir, horizontal well can influence 7700 acres while vertical well only influences 80 acres.

As for general purposes, the gas can be replaced by liquid with density and viscosity smaller than water. Surfactant that lowers the IFT O-W, O-R, W-R would benefit sweep efficiency.

With current high oil price, heavy oil is economically visible to exploit. Estimated cost to lift heavy oil to surface with current technology is US$ 27 per bbl, mostly for heating and mobilizing the oil in the reservoir. Major oil companies are investing on research to decrease the cost.

Heavy oil reserves are so huge, at least two-thirds of world oil reserves or around 2200 billion barrels. Approximately 1700 billion barrels are accumulated in Canadian Athabasca Oil Sands.

SHELL Oil Company recently files a patent related to heavy oil exploitation with total claims of 2468 and more than 400 pages of descriptions. The claims are mostly related to treating heavy oil formations. Developing and managing the formations are also covered including method to drill the wells more effectively, system to develop the field, and power utilization.

FIGURE 1: Steam injection in heterogen reservoir

1. Field development

In treating formation, heat as well as vibration and imbibition are not restricted by rock properties to transfer fluid. Heat and vibration use the rock as medium to move and imbibition uses fluid properties. Heat has other advantages to increase rock permeabilities by means of rock expansion and decrease hydrocarbon viscosity.

In heterogen formation, steam injection (SAGD, CSI) will leave low permeability areas untreated (Figure 1). To continue treatment, heat introduces into reservoir which will not restricted by rock properties to treat low permeability areas. During the heating which can take place for 2-3 years, reservoir pressure will increase. To maintain the pressure below fracture pressure, fluid must be produced. This is especially important for shallow formation to avoid breaking or fracturing the overburden.

FIGURE 2: System for treating formation using nuclear power

Power, the way to introduce the power into reservoir, and duration are very important. The use of nuclear power provides a heat source with little or no carbon dioxide emissions. Also, the use of nuclear power is more efficient because energy losses resulting from the conversion of heat to electricity and electricity to heat are avoided by directly utilizing the heat produced from the nuclear reactions without producing electricity. Figure 2 shows an example of a system for treating formation which uses  self-regulating nuclear reactors.

In the formation containing heavy oil where the the permeability and viscosity are not suitable for steam injection (SAGD or CSI), heating with heat injection rate of 1000 W/m introduces into reservoir for about 1 year. The treatment continue with steam injection until certain rate of oil in the production well achieve. Heating introduces for another 2-3 years.

FIGURE 3: Spacing variation

The duration of heating is influenced by the reservoir tempeature required after treatment and the heater spacing. The value of the hydrocarbon isomer indicate the average temperature in the formation. Weight percentages of n-C7 also can be used to assess the average temperature of formation. After reservoir temperature is reached, steam (SAGD or CSI) or CO2 is injected to drive hydrocarbon to production wells.

Heater spacing that too far will require longer duration. In Figure 3, spacing between heater wellbores greater than about 12 meters may heat the formation too slowly such that more energy may be required than certain nuclear reactors may be able to provide (especially after about 5 years). Spacing between heater wellbores less than about 8 meters may heat the formation too quickly for some in situ heat treatment situations. Heating too quickly can overheat the formation and cause coking.

FIGURE 4: Production profile

Simulator can help to evaluate the project as a whole. A STARS simulation can be used to simulate heating of a heavy oil formation using the heater well pattern. From the STARS simulation, the ratio of energy out (produced oil and gas energy content) versus energy in (heater input into the formation) is calculated for certain heating duration. The total recovery percentage of oil in place is then calculated. Figure 4 shows an example of production profile of heavy oil formation. After heating and producting for about 1.5 years, the production decrease sharply to release gases. The production rise up again to peak production of about 230 bopd. The recovery can reach about 60% or more after about 5 years .

2. Drilling

Tens of wells must be drilled to treat the formation by heat. In the early stage of development, the trajectory of the subsequent well will follow the trajectory of previous well. The drilling string has sensor that communicate with similar sensor installed in previous well (Figure 5). The previous well will become a control well for other new wells drilled around. The sensor can utilize magnetic field, voltage, or radio signals. For better quality of data assessing, the sensor installed in sensor housing that does not rotate (Figure 6).

FIGURE 5: Sensors for well trajectory

FIGURE 6: Sensor housing

After heating running for sometimes, the reservoir temperature climbs up.  Drilling fluid will easily vaporize before reaching bit. By keeping the pressure inside the drilling string above vaporization pressure, the bit can make the hole effectively. The pressure can be maintained above vaporization pressure by designing the nozzle or installing choke above the bit. Adding surfactant to form foam drilling fluid can be considered as alternative.

FIGURE 7: Dual motor

FIGURE 8: Structures for stability

Generally, after reservoir temperature rose up, drilling with conventional drilling string with single mud motor is not stable. It is believe that drilling string with dual motor is more stable and less complicated to develop heated formations (Figure 7).  Special structures such as depicted in Figure 8, are also very helpful during drilling heavy oil containing formation. Cutting structure DOWN will remove protrusion during operation and UP will ream the well and help during pulling out; SIDE will secure enlarging in drilling string structure.

3. Heater

Heat from the heater is transferred into formation either by convection (through fluid), radiation (through vacuum space) or conduction (through metal).  Heater that uses heat transfer fluid is more superior to which uses electric to generate heat since heat directly transfer to fluid from heat source.  In Figure 9, heat generated in nuclear reactor transfer to fluid in heat exchanger unit. Through pipeline, the heated fluid flows into wellbore (Figure 10). The fluid flows through small conduit such as coil tubing to bottom hole and heats formation. The fluid then returns through bigger conduit such as 3-1/2″ tubing to heat exchanger unit. The wellbore is open hole and the formation fluid acts as heat transfer medium to transfer heat into the rocks. Cheap fluid such as water can be used as heat transfer fluid but for lower heat losses, molten salt or another fluid that needs to be heated to remain a liquid is better. In the latter case, another conduit and heat transfer fluid must be used to molten the salt in start-up period, otherwise the salt remain solid in the conduits.

FIGURE 9: Nuclear reactor as power source

FIGURE 10: Heat transfer fluid into wellbore

Electrical heater can use many power sources such as diesel, coal and nuclear. Each power source converts power into electric power and then trasfers it to heater through electric line or conductor. Heat from conventional electric heater is controlled by temperature control system and can overheat oil at or near well. Contrary, temperature limited heater that uses ferromagnetic metal to generate heat eliminates the control system.

FIGURE 11: Inside temperature limited heater

FIGURE 12: Tubular as ferromagnetic metal

Temperature limited heater (Figure 11) can self limit temperature near currie temperature of ferromagnetic metal. There is no adjusment required to  control the temperature. It also delivers more uniform heat transfered into reservoir. Temperature limited heater is more reliable during the treatment in case of maintenance frequency. The ferromagnetic metal can be chosen based on design temperature of the reservoir such as 500 °C or 700 °C, where the heater aoutomaticly stop heating, the alloy determines the temperature limit.  Various metal alloys can be designed to achieve desired output. Ferromagnetic tubular that can be used as a casing (Figure 12) can be acted as temperature limited heater. Inside the tubular is non ferromagnetic conductor which act as power line. Number of layers and thickness can improve the heat transfer and are designed based on heat output required. Molten salt  which is remain liquid during heating is the heat transfer material. The salt composition determines the melting termperature such as solarsalt (sodium nitrate + potassium nitrate) melts at 220 °C and remain liquid upto 593 °C. The composition is influencing the convection and conduction characters to transfer heat. Gas above molten salt will inhibit vaporization. The jacket (Ni) will cover the core from corrosion. Insulated conductor which has electric current will influence ferromagnetic casing to generate heat resistively. Temperature limited heater can be run on coiled tubing (Figure 13). After heater installed, coiled tubing is pulled out.

FIGURE 13: Running on coiled tubing

FIGURE 14: Burning fuel insitu

Heat also can be generated insitu by burning fuel with oxidant  (Figure 14). This elminates power generator, heat exchanger and power line. The oxidizer will increase the temperature upto flash point of the fuel and ignite the fuel. If coked hydrocarbon is available bottom hole, oxidizer (air or oxygen enrich air) may oxidize the coke to generate heat if the temperature is above an oxidation ignition temperature.

FIGURE 15: Electric current flowing through reservoir

It is also believe that hydrocarbon fluid in the formation and the rocks have resistive properties.  Heat sources with electrically conducting material may allow current to flow through the formation from one heat source to another heat source. Heating using electric current flow or “joule heating” through the formation may heat portions of the hydrocarbon layer in a shorter amount of time relative to heating the hydrocarbon layer using conductive heating between heaters spaced apart in the formation. In Figure 15, current flowing to first conduit A may flow through hydrocarbon layer to second conduit B, and back to the power supply. Flow of current through hydrocarbon layer may cause resistance heating of the hydrocarbon layer.

FIGURE 16: Hydraulic lifter to compensate expansion and contraction

During formation heating, parts of the heater will expand and contract after heating diminished. A space at bottom hole must be provided by drilling deeper below treatment area. In Figure 16, a hydraulic lifter is provided on wellhead to compensate the expansion.

Individual fluid properties of layers must be compatible. It is important to ensure no precipitation due to fluid mixing. If fluid mixing trigger precipitation, layers can not be produce commingly, one or more layers must be isolated or squeezed.

During well shut-in and waiting for well service, pressure equalization between layers is happening. Fluid from layer with higher water cut will water saturate and damage other layers. Oil from damage layers need sometimes to recover to condition before saturated by water. Any attempt must be taken to prevent well shut-in. Sometimes, low pressure layer thief fluid from other layers. Shut-in well pressure seems low even other layers have high pressure individually.

In the figure above, the well is completed with multi instruments to detect cross flow between upper zone and lower zone.  A packer is installed between zones to isolate. Similar completion is not limited to two zones.

Flow from each zones is controlled by SSD, choke, valve or ICD. They can be operated pneumatically, hydraulically, mechanically or electrically.

Cross flow is detected by measuring the rate of change of a parameters on both zones. The measuring is  made continuously or periodically over time. The parameters such as pressure, temperature, rate and others if necessary is measured by instruments that held in the carriers. The data are transferred by umbilical to surface and used to determine whether cross flow is occurred. The operator can close the SSD (or choke, valve, ICD), change the speed of the artificial lift, close a production zone or adjust surface apparatus if cross flow detected.

The P,T,Q instruments can be used to measure skin factor by running pressure build-up test.

The inventor also provide a processor that can process the data to determine the cross flow condition. The processor uses nodal analysis, neural network or other algorithm to predict cross flow. If cross flow is detected, the processor sends alarm and give several options to reduce the effect.

Generally, tubulars and vessels inspection is required mostly for safety purposes. A public oil company spends thousands of dollars on inspections to maintain their reputation. Operation departments asks for inspection budged to decrease downtime. Some oil wells with excessive water production are inspected for casing failure. Geothermal well casings are inspected for corrosion failures due to H2S and high temperature fatigue.

In the present invention, the inventor introduces better Electromagnetic Acoustic Transducer (EMAT).  The transducer has core with permanent magnet.  The permanent magnet polarity is changed for switching thereby noise can be eliminated.

Alternating current through electric winding on the core build magnetic field. Together with coil which is induced eddy current  will create Lorentz forces that acoustically excite the object.  Recorded acoustical wave between transmitter and receiver is analyzed to determine the quality of the object.

In recent years, the application of optical fiber for downhole application is more advance. In P / T surveys, the optical fiber is used to transmit  laser light and the reflected light. The frequency and wave length differences are converted to P and T.

Due to the advance technology in optical fiber , now it can deliver high power laser beam downhole with limited power loss. By controlling the wattage and the duration of contact between the light and the rock, the rock can be fractured without melting it. The rock type and minerals must be known to determine the wattage and the duration since each rock and mineral have specific heat and melting temperature. The laser heat will create significant stress in the rocks,  spall the rocks and generate cutting. A purging flow will be applied to flush the cutting and clean up the rock surface from formation fluid.

It is believe, laser perforation can reduce skin and increase permeability up to 500% compared to shaped charges.

The newly drilled well also can be tested by using closed chamber test (CCT) apparatus or wireline tester. Both have shallow investigation radius and most likely are influenced  by mud filtrates. There is no flow to surface on both method thereby no extensive production test equipments.

A development well is tested to assess near wellbore damage or skin factor. Even skin factor is not directly measurable, it can show level of damage around wellbore. In a development well, near wellbore damage might be due to incompatible well service fluid, fine migration, turbulence flow, scaling, clay swelling, and particle plugging. Some damage can be overcome by just flowing the well others need analysis of formation transmissibility, decline rate, remaining reserves, capillary pressure and wettability.

Various models are available to interpret well test measurement and produce skin factor. The model can be for homogenous reservoir or dual-porosity reservoir or hydraulically fractured reservoir. The well test data must be run on all model available and chosen the best match. One popular model is history matching by using pressure derivative. Conventionally, those models produce only one skin factor.

Figure 1: variable skin factor

Actually, skin factor continuously decrease during the production due to continuous reduction of  mud filtrate (Figure 1). In a good perforation and clean-up, the initial and end skin factor are small (number 720 on the picture) but in a bad perforation and clean-up,  the initial and end skin factor are big.

Figure 2: Closed Chamber Test Apparatus

In this current invention of schlumberger, the apparatus (CCT) and method to analyze the measurements are integrated. The closed chamber test apparatus (Figure 2) has improvement . The apparatus  eliminate complicated wellbore dynamic due to surge flow by closing the chamber at optimal time. The optimal time is determined through analysis of bottom hole pressure (BHP). The testing can be repeated several time until measurements are satisfactory . A circulating valve is used to empty the chamber by using Nitrogen as a pusher.

The measured pressures are analyzed by using multi models and functions, analytically and numerically. Reservoir pressure is calculated if not available through measurement. The flow rate can be measured or calculated. The model with the best match is chosen to determine reservoir properties and skin factor.