Proceedings:

Welcome by David Davies followed by Introduction of the Workshop by John Shaw and Jean-Louis Detienne. Preliminary request to add gas injection if there was time and discussion of the official release of PEA-23 data.

The first session was on basic geomechanics issues. Tony Settari outlined:

• qualitative methods for identifying soft formations, and,

• various situations for "fracturing" and the resulting "fracture structure"

For additional information, the presentation is available on Soft Formations, posted previously to the PWRI web site.

Ahmed Abou-Sayed described certain issues of injecting above the fracture gradient in soft formations. Some of the highlights included:

1. In addition to potential areas of dilation around fractures there could be areas of compaction. Dilation implies an increase in volume (and consequently porosity after the formation has yielded. Compaction implies a loss in porosity.

2. The issue of liquefaction was brought up. This was, in one way or another, a consistent theme throughout the workshop - for example, liquefaction accompanying water hammer pulsation leading to sand production.

3. The issue of perforations in soft formations received a considerable amount of discussion. What is actually created and how effective or detrimental are specific perforating procedures?

4. Fines movement and wellbore integrity were raised as issues.

5. The question of what is actually created was raised.

6. Modeling injectivity decline.

7. There was discussion, without agreement and, in fact, with some strong disagreements whether or not disposal operations had better success than pressure maintenance observations. It was argued that disposal operations were performed at shallower depths and that there were fundamental differences in the nature of the injection schemes - the continuous nature of PWRI versus the intermittent character of disposal operations. It was also suggested that there might be fewer pressure restrictions imposed on disposal operations.

8. In-situ stress conditions and their influence on successful injection were emphasized by Brian Smart and Nick Koutsabeloulis.

9. There was further discussion of the role of perforations. Some people argued that the effectiveness of the perforating would only lead to problematic startup and that afterwards the perforations would not be a substantial issue. Robert Angel indicated that Marathon was successfully applying the KISS perforating methodologies where it was desirable to create a large hole but only just penetrating through the casing and the cement sheath.

10. There was considerable discussion of N. Morita's SPE paper in regard to behavior of perforations in soft materials and the characteristics of the damage that was generated by perforating.

11. Another common theme arising in the discussions associated with this presentation was "What measurements should be made to identify what is occurring during injection above fracturing pressure? Falloff testing may or may not be able to determine what type of feature has been created."

Paul van den Hoek presented two case studies.

1. The first was a hard rock situation where the formation could not be broken down. Various attempts were made to overcome this problem, including perforating openhole, setting a plug to isolate a small interval and backflow to remove skin.

2. The second case, in soft sands, showed step rate data where it appeared that there was fracture-like behave at injection pressure levels significantly below the stresses that would be required for fracturing. One data point did in fact seem to indicate that there had been injection at pressure levels that could be attributed to breakdown and that subsequent lower injection pressures were in fact characteristic of fracture behavior. Laurence Murray suggested that skins should be calculated for the data points on the lower slope part of the step rate plot to assess if skin was zero or negative, which would indicate whether or not fracturing had actually occurred. Various participants indicated that part of the difficulty could be attributed to definitions. The frac gradient had been supplied to Paul by his operations colleagues and the stress level indicated by this frac gradient was above any of the pressures measured during the step rate testing (except the one point previously mentioned). It was suggested that the problem was one of definitions - that the "frac gradient" supplied to Paul represented the pressure required to cause the creation of a significant fracture at the wellbore (for example, the breakdown pressure divided by the depth) as opposed to the stress resisting propagation of a fracture (the minimum in-situ principal stress divided by the depth).

This focused discussion back onto diagnostics issues - for example, that it would be appropriate to confirm fracturing by assessing the level of skin associated with a particular rate/pressure combination. There was also discussion as to whether PE injection can be more effective than clean water injection because of impeded leakoff.

Jim Sommerville briefly outlined considerations for testing core samples to provide information relevant to determining the properties necessary for characterizing the stability of a wellbore in a weak formation and the behavior of material around a wellbore when pressure was increased as a result of injection. Some of the salient areas included:

1. Difficulties in preparing samples for testing from soft formations

2. Basic techniques for determining failure parameters (to assess stability and compaction characteristics)

3. Methods for doing thick-walled cylinder testing

4. Discussion of the influence of stress path on the results that are generated during laboratory testing. Jim emphasized that laboratory testing must be performed in an appropriate manner to provide results that are meaningful for field usage.

5. Presumably, an expanded discussion of this is required for a Best Practices Document, indicating what types of laboratory testing should be performed and how they should be performed to provide legitimate information for stability assessment and completion design. This came to light in further discussion on the second day of the meeting where there was debate on establishing an unconfined compressive strength above or below which stability of an openhole would become an issue.

John McLennan briefly presented methods for determining thermal characteristics of rocks. The major points were:

1. Thermal conductivity can be measured and its major influence was usually in determined how much heat would be lost to overburden and underburden.

2. Convective heat transfer associated with moving fluid is the dominant mechanism for temperature change in the target injection zones. It is largely controlled by specific heat. This can be measured but it can be estimated quite accurately from the weighted average specific heats of the individual components of the reservoir (minerals, saturating fluids).

3. In hard rock, the coefficient of thermal expansion controls the potential for thermal stress fracturing. In low modulus materials, stress changes associated with thermal changes are small. The question was raised whether or not strain changes in poorly consolidated materials, associated with changes in temperature could alter permeability and/or integrity? The answer to this is uncertain. Away from the wellbore the influence is likely small.

4. Additional thick-walled cylinder test data were provided. Unusual failure patterns were identified by x-ray tomography. The two issues were that current models may not be adequately explaining this behavior and secondly that even in soft formations, with the application of stress, localized failure zones can result with inferred local changes in permeability. Nick Koutsabeloulis observed that he had encountered similar behavior and that it could be explained on the basic of anisotropic characteristics of a reservoir.

Bjarni Palsson summarized public domain and JIP literature relevant to various completions techniques in soft formations. Basic observations included the following:

1. Screening criteria. One of Tony Settari's criteria for soft formation selection was that drilling was difficult. This was disputed and will be removed from the list. Field input strongly indicated that this is not necessarily the case.

2. The failure "mechanisms" (or activities causing failure and sand movement) most commonly cited in the literature were backflow, crossflow and water hammer "loading."

3. N. Morita's SPE paper again became a subject of discussion. Morita argued that 70% of the pressure drop commonly occurred in the perforation area. Ahmed Abou-Sayed disputed this indicating that he could not see how there could be significant damage if material was ablated into the perforation only. Clive Bennett indicated that damage can be attributed to charge debris. Others argued that indeed there would be a dissagregated zone around a perforation tunnel and that this could ultimately be squeezed into the tunnel by stress conditions.

4. A strong message brought out by Laurence Murray was that producers and injectors cannot be considered together and that features characteristic of producing wells cannot be directly translated to injection situations.

5. The consequences of water hammering in the Heidrun field were outlined, as were methodologies for reducing the impact. Petrobras has argued that retainer valves have cured this problem in the Marim field.

6. Examples were given from the Wilmington field (old data) as well as more recent data where steam injection has served to provide consolidation of the wellbore because of reprecipitation of certain silicates.

7. Experience in the Forties Field was provided. There had been crossflow and consequent sand production and fillup. Laurence Murray indicated that HIT testing had identified cavities. (In general, it was indicated that cavities can also be identified by pressure response and required volumes in water shutoff treatments and by behavior and volumes during cement squeezes.)

8. Bruce McIninch observed that Marathon has seen situations where there was no significant pressure response when some pills were pumped until they were overdisplaced by about five times.

9. Cavities were discussed by the general audience. There is some belief that cavities do exist in some injectors. There is a subsequent question relating to what are the causes of injectivity degradation in wells with cavities.

10. Bjarni and others presented a list of some of the new generation innovations that may be applied to soft sand injector completions - including expandable sand screens and intelligent completions.

Ahmed Abou-Sayed summarized some of the considerations in "Injector Operations Philosophy". The list below is not complete (refer to the presentation for complete details).

1. What are the objectives of the operation? For example, is it injection into a reservoir sand for sweep or injection into the water leg for pressure maintenance or disposal, etc. and how does the specific objective influence the completion and management operations?

2. Issues that are relevant for deployment included the beanup/down rates, the specific completion, what type (if any) of sand control is required and what monitoring methods should be implemented (PLT, microseismic, etc.).

3. Different design and management protocols are required depending on the type, shape and length of the well. Some of the issues discussed with regard to horizontal wells were temperature issues and how preferential fluid intake at the heel could be overcome (running tubing to the toe, dual completions, fracturing the toe during completion…). Håvard Jøranson supported this citing one PLT on a horizontal well where all of the injection was occurring at the heel. Laurence Murray emphasized the need for detailed temperature information to determine what was happening - fiber optics techniques were cited.

4. Producer-to-injector conversion considerations were indicated although specifics were not provided. This was discussed to a limited extent on the second day of the workshop.

José Piedras described Natural Sand Packs (NSP) entailing a screen in an openhole and allowing or encouraging sand to come in around the screen. Laboratory tests were described to characterize sand burst and backflow. Work by Rogaland and Johnson was cited on screen erosion. Some of José's observations included:

1. WWS's were recommended? For inverted WWS, Elf's laboratory testing indicated no sand arching and production of considerable amounts of sand. The maximum sand production occurred at the start.

2. Shales have been isolated with blanks or ECPs

3. For matrix situations, screens interspersed with blanks can be successfully used to distribute flow

4. A sacrificial screen can be run at the end of the other screens

5. In a basic literature search laboratory procedures could not be found for injector screen design. Consequently, Elf tested 2 WWS, 1 premium and 1 ESS

6. Low filtration threshold; fine gauge - to keep all fines in the formation.

7. For cleaning and filtration, partition the screen to eliminate a screen annulus.

8. Surface screen filtration was discussed.

9. The recommendation was circulation of two tubing volumes and that there should be a specific surface check with the screens actually being used.

1. Do not use slotted liners.

2. Do not use chemical consolidation techniques.

3. Do not squeeze with mud acid.

4. Do not backflow for screen "cleaning."

5. Do not attempt to cleanup if injection is in the fracturing regime.

6. Do not clean up if there is saturated salt mud.

1. Casing is set in the upper sands

2. If possible, only complete one zone with only one reservoir characteristic.

3. Use a bottomhole flow control device.

4. Perform an injectivity test after completion.

5. If the specific injection fluid is not available, do not place any damaging fluid in the tubing and prevent formation of hydrates in the wellhead and other surface equipment in environments where hydration formation is possible.

6. If there is cake cleanup, use a knockout valve (KOIV). If there is deeper cleanup into the formation use a surface controlled subsea valve (SCSSV).

7. Use partitioned screens.

1. Be sure to use soft shut-ins and restarts.

2. Provide adequate QA/QC of the injected water (solids, oxygen, scale prevention ...).

3. Management of the injected water.

4. Provide surface pressure and flow rate monitoring.

5. Flush all lines and pumping equipment before resuming injection.

6. Do not use grease on wellheads or manifolds.

7. Provide a surface filtration system using an actual downhole screen to monitor performance.

1. Determine fillup.

2. Laboratory investigations.

3. If acid is used, keep the concentrations low.

1. Average slot tolerances

2. Slot no-go and go.

3. Wire design

4. Geometric and metallurgical characteristics.

José Piedras finally presented considerations on converting wells to producers. The issues to consider include:

1. Well selection (the reservoir, the field situation, the platform and the available facilities).

2. Completion selection (the state of the near wellbore area, sediment, integrity of hardware - metallurgy, test tubulars, annulus, wellhead - the specific hardware and jewelry - tubulars, GLM, packer anchors, nipples …, scale

3. Fluid selection (ensure compatibility with reservoir fluids and solids).

Clive Bennett presented a number of BP Amoco examples. These included:

1. Harding. Two wells, deviated at 60^o were discussed. An 80-m section was underreamed and OHGP. This was a matrix injection only situation. Produced water injection followed 95% aquifer injection. One well behaved acceptably. The injectivity on the second degraded in conjunction with a plant upset. Laboratory studies indicated the susceptibility of a poorly gravel packed formation to plugging. Mutual solvents were considered for stimulation. Hypochlorite was also suggested. Safety issues should always be considered. Consideration has also been given to protecting this one well because of its position in the manifold.

2. Clive presented another Harding well example. The permeability was 10 darcy (matrix injection) and the net to gross ratio exceeded 98 percent. There was injection into a single channel in a very unconsolidated sand (an unconfined compressive strength of less than 10 psi). The well was horizontal with 540 m or pre-pack screens in openhole. Injection was maintained at 35,000 BWPD with an injectivity index of 220 BPD/psi. There was interference between this well and a producer. This should be a design consideration. Also, a PLT indicated that 50 percent of the flow in the injector was into the first 70 m. In the production well that was taking water, PDK logs indicated water entry at the heel. The well profiles of the producer and the injector diverge from heel to toe. Channelling is suspected and a proposed workover option was to put blank pipe in the heel of the injector to promote injection closer to the toe. (There is additional Harding data in SPE 48977).

3. The next situation described was tighthole. It was a deepwater turbidite environment (permeability of 400 md, a net to gross ratio of 70 percent). Injection was into a single zone, above fracturing pressure. This was an unconsolidated/friable sand with unconfined compressive strengths between 200 and 500 psi. Four wells were cased and perforated and two wells had screen completions. The cased in perforated injectors in one panel are either maintaining injectivity and providing good pressure support or have a good prognosis - for the latter situation, the one relevant well is taking 15,000 BPD below fracturing pressure. In the other two proven wells, rates have been maintained when the BHIP has been dropped below fracturing pressure.

The wells that are cased and perforated have had a large sump, where possible, based on the strength of the rock, owing to concerns associated with incomplete cleanup for the screen completions.

Data was provide on one of the wells completed with screens. The interval was short. Completions fluids were bullheaded into the formation. There was declining injectivity and this is probably associated with a confined fracture and localized buildup of reservoir pressure. A substantial drop in injectivity is encountered when the BHIP is less than the fracturing pressure.

There is no clear understanding yet of the impact of completion and cleanup design. Further clarification is anticipated when the other screened well (screens and partial cleanup) is brought on above fracturing pressure.

There are some facilities issues. A leak in the sub-sea water injection system is currently restricting injection to below fracturing pressure. Lack of sub-sea valves limits the ability to isolate sections of the system (i.e., a leak in one part may compromise the performance of the entire system). Also, since there is a lack of remotely activated chokes, the injection program is impacted (ROVs are required and weather restrictions are consequently more important).

At some point in this presentation, there was a discussion by several parties in the difficulties inherently involved with ECPS. Various parties reported substantial failures. Cement inflation has not been tremendously effective. Mud inflation has been successful. They have worked well when stage cemented. Failures of ECPs have been reported when they have been set against competent formations.

4. The next case that Clive presented was for single and multiple injection into an environment with permeability ranging from 200 to 3000 md. The associated strength of the sand varied from 50 to 2000 psi. Seven water injectors were completed with screens and one was cased and perforated. There were two high angle wells (one well was three zone and the other was single zone). Cleanup was accomplished by bullheading the mud into the formation or by partial cleanup to the rig. Injection is above fracturing pressure.

There has been an increase in near-wellbore pressure in most wells due to poor communication between the injectors and the producers. Wells that have high GORs can't get good support. This was seawater injection. It has been determined that this is a reservoir problem. Approximately one hundred reservoir pockets have been identified. Recently, there has been improved pressure support and lower GOR because of injection up-time and varying well rates. With the injection above fracturing pressure, there has been no evidence of fracturing out-of-zone but there are some concerns that this is a risk.

It was pointed out that 4D seismic has proven valuable in identifying pressure distributions and delineating problems in advance of breakthrough. The need for quality surveillance data was emphasized (inflow and temperature profiles, fiber optics methods…). The need for improved surveillance methods has become apparent for multi-zone injectors.

Pressure falloff testing and material balance data (i.e., indirect evidence) have suggested that there is injection into all zones (including the high angle multi-zone injector).

There is no evidence that bullheading the drillin fluid impacts performance any differently than clean-up to the rig.

It is planned to shut-in two of the injectors because there is no evidence that they are providing support to the producers.

In the next well (two zones), it is planned to fracture the toes through DP before/during bringing them on line to assist in the inflow.

They are also looking at ESS.

5. Finally, Clive presented a flow chart that is used in some aspects of completion selection (Figure 1).

Laurence Murray presented information from previous laboratory evaluations. Experiments have been done where there was dynamic filtration on Berea sandstone core. Brine containing 20 ppm oil and 200 ppm solids was first flowed through the sample and then by manipulating a valve at a specific pressure, it was also allowed to flow across the sample face. Post-sample evaluation showed a filter cake on the surface that was 1.3 mm thick. Quartz grains, ranging in size from fine silt to medium-grained sand, are suspended by injected fines in the "upper" (near surface) part of the filter cake. Below this, suspended fines are not present and the cake appears to be denser. There was an observable injected solids penetration into the sandstone matrix of 0.2 to 0.4 mm. Oil invasion extended 8 to 10 mm into the sample.

The message was that solids dominantly tend to stay in the fracture and that oil damage may be the dominant issue and that oil may bind the particulate material.

Laurence also presented an example of a method used to ensure (in hard rock) that the perforations are clean, prior to injection in order to improve conformance. Perforating was done underbalanced, and the well is backflowed at five gallons per foot. The well is then broken down with clean water and flowed back at least two tubing volumes.

Bruce McIninch outlined Marathon's West Brae subsea development, focusing on a joint development with Sedgwick, in approximately 350 feet of water. This is located in Block 16/7a in the UK Central North Sea. Two sandstone reservoirs are involved (Eocene Balder and Flugga sandstones). These are normally pressured, unconsolidated, submarine channels. The Balder sandstone has a porosity of 28%, permeability in excess of 2 darcies and contains viscous, heavy oil 22^o API). The deviated injection well is W4, located between two structural highs with gas caps.

Reservoir pressure is close to the bubble point. Further pressure drop could not be tolerated and pressure maintenance became necessary. The targeted injection was 30,000 BWPD. Simulations indicated that one support well would be adequate.

The methodology was to provide sand control without gravel packing, based on poor injection histories for some gravel packs. The facility had 3000 psi of injection pressure available and gas lift mandrels were installed for backflow. Backflow to the rig was allowed during cleanup.

Screens were required for cleanup and for during pressure surging. They looked for plating on the inside of the screens. Measurements performed on a blanked and plugged screen showed that it would fail at 1350 psi. Consequently flow back would be restricted to 1300 psi. This was never an issue.

Bruce discussed aspects of the drill-in fluid used across the reservoir. Marathon drilled through the formation with water-based mud. They used sized salt for the injectors and carbonate for the producers. Their experience (and per Laurence Murray, BP's) indicated that carbonate could not be effectively removed in injectors. The salt sizing was based on laboratory return permeability testing.

The specific operations on W4z were as follows.

• Drill 12-1/4 inch to TD with SOBM.

• PB set 9-5/8 inch.

• Drill 8-1/2 inch with NaCl based DIF with MgO oxidizer

• The well was displaced to filtered brine.

• 6-5/8 inch screen (110 micron Excluder) was run.

• An acid soak was performed to clean the filter cake.

• The well was backflowed to remove residual filter cake.

• Four hundred feet of reservoir was encountered from 6050 feet TVD to 8150 feet MD.

• During the cleanup, 5% HCl soaks were used. The upper completion was installed and the well was backflowed for seven hours. Water samples were taken.

Currently injection is 20,000 to 30,000 at approximately 1700 to 2100 psi. Although there has been no real reduction in injectivity in approximately two years, it was indicated that the high injection pressures have been disappointing. Damage has been attributed to breaker pill control. Mechanical damage and friction also contribute to the injection pressures. It is also hypothesized that they were unable to get as much acid into the formation as they would have desired. Bruce felt that the injection pressures are still slightly below fracturing pressures although there was some speculation by other participants that the magnitude of the THP suggested that fracturing might in fact actually be occurring. An approximate injectivity index estimated roughly from the THP versus rate plot at 30,000 BWPD is 30000/2100 (ignoring friction) ~14.

David Davies polled the audience for views on plastic coated tubing. Elf uses it in the Cameroons. Laurence Murray indicated that ceramcote was possibly more robust. The concerns can include use in subsea gas wells if exposed to gas and how it stands up to rapid pressure release. The issue is to ensure the right coating for particular service conditions. BP uses coated tubing on subsea wells as a matter of course. Statoil and Shell use GRE. BP has found good drag reduction and corrosion protection for a small incremental cost (drag reduction of 40% on one well).

Robert Angel discussed MOC GOM soft rock completions in the Ewing Bank area. The Ewing Bank 873 lease was acquired in a 1990 lease sale. It is located 200 miles south of New Orleans in 800 feet of water at the platform. Marathon (67%) and Texaco (33%) are partners. The discovery well and three additional wells were drilled from a subsea template starting in December 1990. The platform was installed in June 1994 and production started in August of that year. There are seventeen producers, three water injection wells and three sub-sea wells (Arnold, Oyster and Manta Ray) on the platform. There are a sixteen-inch oil pipeline and a thirty-inch gas pipeline currently delivering 55,000 BOPD and 47 MMscfD of gas.

The completion interval varies from 32 to 256 feet interval length at depths between 10,000 and 13,000 feet TVD. Wellbores are deviated between zero and sixty degrees. Production is from the Pliocene Bull sand with a permeability between 400 and 1600 md. Reservoir fluid viscosity varies from 1 to 4 cP, with gravities between 18 and 25^o API. The completions have been carried out in two stages (1994 - 1995 was Stage 1 development and 1997 - 1999 is classified as Stage 2 development).

The wells were fracpacked. Progressive development of skin was noted with time. Two of the injector wells experienced significant mud losses during drilling. Perforation fines during Stage 1 were a possible issue. This is a seawater injection operation, below fracturing pressure. The observation, which may be characteristic of many matrix operations, was:

Acid treatments lead to brief increases in production, followed by decline. Improvement was less each time a well was treated.

Robert provided a comparison of operations during Stage 1 and 2. Only producer information is available for comparison of the two stages. The comparative operations are shown in the Table below.