SPE 83957 Valhall Field - Still on Plateau after 20 Years of Production

Copyright 2003, Society of Petroleum Engineers Inc. This paper was prepared for presentation at Offshore Europe 2003 held in Aberdeen, UK, 2-5 September 2003. This paper was selected for presentation by an SPE Program Committee following review of information contained in an abstract submitted by the author(s). Contents of the paper, as presented, have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material, as presented, does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Papers presented at SPE meetings are subject to publication review by Editorial Committees of the Society of Petroleum Engineers. Electronic reproduction, distribution, or storage of any part of this paper for commercial purposes without the written consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of where and by whom the paper was presented. Write Librarian, SPE, P.O. Box 833836, Richardson, TX 75083-3836, U.S.A., fax 01-972-952-9435.

Abstract The estimated recoverable reserves from the Valhall field at start of production in 1982 were 250 MMSTB. Now, after twenty years on primary depletion, a total of 500 MMSTB has been produced and additional 500 MMSTB remains to be produced of the original 2.6 BSTB in place. This corresponds to a recovery factor of 40%. Possibilities to increase ultimate recovery have been defined. These will require further insights into the detailed architecture of the field and improved understanding of the reservoir energy and displacement efficiency. Approximately 50% of the drive to date has been from rock compaction. The field is a North Sea Chalk field producing from Tor and Lower Hod Formations, porosity is exceeding 50% in places, some fractured permeability is present, but matrix permeability is generally low, less than 10 mD. Application of new technology has been fundamental in bringing the field up to current performance. New completion techniques combined with dedicated draw down schedules has been established to reduce influx of the weak chalk formations and reduce well failures. Special well design for a compacting and subsiding environment has also been implemented. Drilling of the overburden has been a key challenge. This has been partly mitigated by detailed geological mapping of problem zones versus structure, lithology, overpressure and wellbore stability analysis, but has also resulted in replacing extended reach wells by the installation of new flank drilling and production facilities. The particular characteristics of the overburden and chalk also pose challenges for data acquisition. Coring technology & practices are very tightly controlled, as is selection of logging devices.

A water flood scheme has been approved based on a successful water flood pilot, but issues related to sweep efficiency, presence of fault and fracture zones and large variation in thickness need to be understood to capture it’s full potential. The reservoir will also experience extra water induced compaction and increased subsidence. New logging technology has recently made it possible to define and characterize the fracture system, which combined with a range of surveillance techniques will be key in this work. Seismic imaging has generally been a challenge at Valhall due to the presence of gas in the overburden. Use of 4C seismic technology has improved this. In addition, the 4D seismic response appears to be very sensitive to production-induced depletion, compaction of the reservoir and subsidence of the overburden and seafloor. Seismic techniques will be critical in future development. For a more detailed review of the first 10 years of Valhall, reference is made to the paper by Ali and Alcock [1]. Field History The Valhall field is an over-pressured, under-saturated Upper Cretaceous chalk reservoir located in the North Sea approximately 290 km offshore southern Norway in 69 m of water. The field is located in the most southwestern corner of the Norwegian continental shelf, Figure 1. The Valhall field was discovered in 1975, after exploration drilling in the period 1969 – 1974. Decision to develop the field was made in 1978 and the field started producing in October 1982. During appraisal drilling the first issues with soft chalk and solids production were experienced. Although early core tests indicated a high compaction potential, it was believed that the relatively thin chalk section would not result in significant subsidence. The platforms, however, were built tall enough to withstand some subsidence. The initial development consisted of a 3-platform complex (quarters platform, drilling platform and process/compression platform). Later, in 1996, a fourth platform was added (wellhead platform) to provide additional slots for infill drilling. In 2000, the Valhall partnership approved a water injection program, from an additional Injection platform, IP. With continued subsidence, drilling wells in the overburden became increasingly difficult. To provide efficient access to the flank areas in the North and South, installation of two new wellhead platforms was approved in 2001.

SPE 83957

Valhall Field - Still on Plateau after 20 Years of Production Olav Barkved, Pete Heavey, Roar Kjelstadli, SPE, Tore Kleppan, and Tron Golder Kristiansen, SPE, BP

2 Barkved, Heavey, Kjelstadli, Kleppan and Kristiansen SPE 83957

Geological Settings & Data General The Valhall Field is a double plunging NNW-SSE trending anticline, Figure 2. A simplified reservoir zonation is shown in Figure 3. The primary reservoir is the Tor Formation with secondary reservoir from a unit within the Hod Formation. The thickness of the Tor reservoir varies abruptly ranging from 0 to 80 m. The reservoir quality varies considerably with some of the best porosities (42 to 50%) and permeability (1 to 10 mD) developed in the thickest areas. Generally, the Tor Formation has higher porosity and permeability and provides the greatest reservoir volume within structural closure. The high porosities found within allochthonous or re-deposited chalk intervals, are preserved by fluid over-pressuring before oil emplacement, and decline with depth. The thin areas (0.5m to 10m) generally have a skim of high porosity chalk overlying a dense hardground. The lateral change from a thick to a thin can occur abruptly - making for challenging horizontal drilling. Structural Evolution & depositional model Presently, Valhall Field is at the highest structural position along the Lindesnes Ridge in both the strike and dip directions. A cross-section across the field is shown in Figure 4. The basic characteristic of an inverted structure is the antecedent structural low, which has been transformed into a relative positive feature. The strong variations in Tor and Hod formation thickness across the structure reveal various stages of development of a growing structure. Understanding the details are important for the zonation of the reservoir, detailed discussions can be found in Farmer and Barkved [2]. The graphic correlation technique, Mann and Lane [3], has been used for detailed biostratigraphic analysis of the chalk and overlying shales. Using graphic correlation and sequence stratigraphic techniques, the age and the nature between the formations has been established. The most important stage is the forming horsts and graben in the Campanian as a result of extension across the top of the growing structure (syn-depositional faulting). In the Maastrichtian, chalk sediments of the Tor filled the crestal grabens. On highs (close to storm wave base or current swept areas), net sediment accumulation is low, and “dense zones” and hard grounds are formed by early cementation. On structural highs, sediment packages are thinner, hardground development is pronounced and gap in depositional record are considerably more extensive than on the flanks and in deeper parts of the basin. By the end of the Maastrichtian, most of the grabens had been filled; the anticline remained structurally high and provided less space for the younger Paleocene formations. Only a thin condensed section (high gamma shale) equivalent to the Ekofisk and Våle Formations blanket the crest of the structure. Regional thinning of the Paleocene, Eocene, Oligocene, and

Miocene intervals across the Lindesnes Ridge indicates that a structural high was present until the early Miocene. Petrology of Chalk Chalk is predominantly composed of fragments of coccospheres – calcareous planktonic algae, with minor contents of planktonic foraminfera and fragments of larger fossils like bryozoa. The coccospheres are complex structures 2-20 microns across comprised of individual calcite plates or coccoliths, a typical volume of 0.3 to 1 micron3. Chalk would be referred to as a mudstone in a clastic classification. Additional constituents of the chalk are small percentages of clay and clay sized quarts particles. The volume of this material ranges from one to more than twenty percent. The amount and the distribution of these elements and the packing and preservation f the coccolith fragments (texture) have an important impact on the dynamic properties of the Chalk. Reservoir Zonation The Tor Formation has been divided into four reservoir zones based on detailed biostratigraphy; Tor-D, Tor-M1, Tor-M2, Tor-M3+ (incl. Tor-Ca), Figure 3. The Tor Formation consists of chalk deposited in the Danian, Maastrichtian and Campanian periods. The Hod Formation age is Santonian, Coniacian and Turonian, Andersen [4]. The Tor Fm. is bounded by unconformities at the top and base. The Maastrichtian Tor reservoir zones (Tor-M1, Tor-M2 and Tor-M3) are present over the crest of Valhall Anticline as well as on the south flanks. The Tor-M2 and Tor-M3+ zones appear to be confined to the deepest crestal grabens and downflank areas. The most complete stratigraphic section is found in the flanks or in local structural lows. This includes an older Campanian Tor zone and a Campanian age chalk containing reworked Hod age microfossils. Hydrocarbon source & Reservoir Seal Source for oil at Valhall Field is from the Upper Jurassic Mandal Formation (Kimmeridge Clay). Oil generation occurred during Early Miocene to the present time. A 1000m thick Tertiary claystone section of primarily Paleocene, Eocene and Miocene age overlie the chalk section and provide the top seal at Valhall Field. Escaped hydrocarbons from the chalk penetrate and permeate micro fractures in some of these claystones, and the matrix in highly diatomaceous and low-density sections in the Miocene, leading to the low seismic velocity "gas cloud" overlying the central parts of Valhall Field. Petrophysics& logging Table 1 summarizes the pertinent reservoir rock and fluid property data for Valhall. Valhall Field wells falls into two categories, early exploration wells drilled with water based mud, and development wells drilled almost without exception with oil based mud. For the exploration wells, porosities are

SPE 83957 Valhall Field – Still on Plateau after 20 Years of Production 3

calculated directly from the density logs, assuming a lime matrix of 2.71 g/cc and a fluid density of 1.0 g/cc. A change to this procedure is necessary when calculating porosities from density logs in the development wells using oil-based mud. Variations to standard techniques are also required when using LWD tools, as it can be demonstrated that the light high GOR Valhall crude is incompletely flushed away from the wellbore at LWD time. Petrophysical studies have shown that the Archie equation provides a reasonable method for calculating water saturation in Valhall wells. Connate water saturations in the crestal Tor Formation are typically less than 5%. During the last 10 years, considerable efforts have been directed towards improving the understanding of porosity distributions and relations to saturation and depth. Using seismic data to map and understand the lateral variation in porosity away from wells, and integrating log with capillary pressure data, has been central to understanding distribution of hydrocarbons within the field boundaries. As a result of improved porosity and saturation models new well locations have been identified and drilled. Natural Fractures Initially the crestal part of the field was naturally fractured, Ali and Alcock [1]. Total permeability estimates from production tests were more than ten times matrix permeability. During pressure depletion, the fractures closed in some parts of the field, and permeability declined. This caused rapid decline in rate and was seen in build up response and PTA. Powley et. al. [5], compared permeability decline with pressure depletion. This permeability decline is not uniform across the field. In some areas of the field, fractures stay open. Poor core recovery of semi-unconsolidated Tor chalks and the difficulties in using advanced fracture detection tools such as resistivity or acoustic imaging logs log, has historically made definition and resolution of fracture systems and structural detail at Valhall difficult. The recent development in oil based resistivity imagers and LWD density/Pef image logs, coupled with procedures for core cutting, tripping and handling has improved this. The modern logs provide vital detailed insight into the nature and distribution of chalk. Work is ongoing to identify important fractures using micro-mud losses and drilling parameters in addition to well logs. Data Management With the level of new well activity planned at Valhall, the new LWD realtime azimuthal density tools, formation pressure tools and rotary steerable systems provide data at unprecedented rates. Getting this data in real time is critical to make the right decisions. The fibre-optic cable from Valhall is currently pressed into use providing realtime data via WITSML and OPENWIRE ™ to get drilling, mudlog, and

LWD into the digital workspace of the reservoir team in near real time. In addition to biosteering inputs, this dataflow facilitates accurate placement of geosteered horizontal targets using all data available. This is becoming more important as development progresses in areas with thinner or more complex structural characteristics. In addition, critical operations can be monitored very closely by key onshore staff. An example of this is “geostopping”. To avoid total losses drilling into depleted chalk a drilling liner needs to be deployed. In these cases, drilling will have to stop within 5m TVD of top chalk to allow safe deployment. Losses would expose the weak overburden to strongly reduced hydrostatic pressure and could result in stuck drill pipe. Wireline acquisition can also be monitored by expert petrophysical staff in realtime via the BP Norway Onshore Operations Centre. It was constructed specifically to support the IP drilling program, but has proven itself to have many valuable uses, including the realtime monitoring and control of propped-fracture stimulations. With 20 years of data and reporting, and with the prospects of another 25 years, it is critical to get data management right; both for internal use, and for external reporting requirements to partners and national datastores. To this end, efforts are ongoing to improve and further standardize workflows and products, right down to data mnemonic standardization. After a tracked QC process - which also results in HQLD (High Quality Log Data) reporting to the national datastore - well log, mudlog, stratigraphic, lithologic, completion, perforation and directional data are stored in a protected database, administered within the subsurface team, which is then used by all in the team as base data for interpretation. This avoids unnecessary duplication of databases and attendant errors. Preliminary and real-time data is flagged as such. Use of the abundant historical drilling data in planning new wells, and identifying potential trouble zones in existing wells is a challenge. This is being achieved by consistently coding up drilling observations, such as high torque, mud losses, stuck pipe etc., so that these data can be used in 3D during the planning, execution and post appraisal phases of a well. Role of Seismic Data Seismic data deliver the thickness variations, fault definitions and subsurface topography needed for optimal well placement. Due to rapid lateral variations in thickness of a relatively thin reservoir, seismic is critical for detailed well planning and drilling of horizontal wells needed to drain the field economically. There appears to be a strong correlation between overburden faults and drilling problems. Seismic data is critical in defining a safe well trajectory avoiding potential troublesome faults. The presence of a low velocity gas-charged Miocene diatomaceous interval creates a "gas cloud" effect that distorts the seismic time data and makes it difficult to image the


crestal area of the reservoir with conventional seismic techniques, Figure 6. Outside the “gas cloud” area the seismic quality is very good, and the seismic data has been vital in developing the flank areas. Figure 7 demonstrates the potential of seismic attributes to define areas of optimal reservoir properties, Barkved, [6]. Advanced processing of conventional 2D seismic combined with extensive use of VSP to undershoot the gas cloud was the seismic tools used during the first ten years of production, Leonard and Munns [7]. In 1990 the first horizontal wells were successfully implemented, this raised the need for improved lateral seismic coverage, and since the early targets for horizontal wells were outside the “gas-cloud” area, a 3D seismic dataset was acquired in 1992. The 3D seismic data provided a better basis for validating earlier well observations. A significant area in the northern part of the field, previously mapped as thin due to a well placed at a localized reservoir high were immediately pointed out and later confirmed by drilling. The resulting increase in reserve was close to 40 MMstb Oil only for this area. The step change in detailed reservoir characterization from 3D seismic coverage soon raised the need for technology that could provide seismic images of the reservoir beneath the gas cloud. Pre stack migrations were tested out and 3D VSP was considered , but the partnership agreed to pursue the potential in utilizing the emerging four component (4C) seismic technology. The Valhall field has been instrumental in developing and demonstrating the viability of imaging below gas using converted shear waves recorded by four component sensors placed on the seafloor, Thomsen et. al [8]. Converted shear waves are converted reflected energy from down-going compressional (p-wave) seismic energy, at the acoustic interfaces in the subsurface. One of the world’s first 3D 4C seismic datasets was acquired at Valhall in 1997, Rosland et. al [9], Barkved et. al [10]. Images constructed from this dataset are today essential in planning new wells in the central area of the field, Figure 8. The acoustic setting of the Valhall reservoir is such that strong 4D seismic responses should be expected. In 2002, a second 3D dataset was acquired demonstrating “stunning” 4D responses clearly defining how wells are draining the field, Figure 9, Barkved et. al [11]. The observations from the 4D seismic have already been used successfully to plan and drill new wells. The 4D seismic is very sensitive to minor changes in effective stress in the reservoir, and there are indications that pressure changes in the order of a few hundred psi might be predicted from the seismic. The 4C technology is still very much in an emerging state, and new and improved processed results have been provided on a regular basis. This acquisition provided also wide azimuth P-wave data set, which has provided new insights into small

scale faulting in areas of generally good data quality in the flanks by illuminating the subsurface from all azimuth angles. The P-wave data set has also been analyzed for AvO-Azimuth effects. These analyses revealed azimuthal anisotropy effects, which showed strong correlations to existing fault patterns Hall [12]. The converted wave data has also been analyzed for shear wave splitting. Early analysis pointed out the presence of shallow azimuthal anisotropy effects, probably related to subsidence; and detailed analyzed has now demonstrated the orientation and magnitude of the shear wave splitting effects is closely related to the shape of the subsidence bowl at seafloor, Figure 10. Currently, various approaches are tested for isolating these effects to the reservoir level, and the intention is to use this information to validate realizations modeled by discrete network fracture modeling. Other seismic techniques as the Coherency processing and spectral-decomposition has been used to better define faults in the reservoir. These techniques are actively used in well planning, when a rigorous and detailed 3D model of the subsurface is constructed to guide optimal drilling of a well. Reservoir & Field Operations Reservoir characteristics The high porosity and low matrix permeability has given relatively low gas mobility. This has been seen in field observations, and confirmed by gas-oil relative permeability measurements. Figure 11 shows field GOR over 20 years of production history. The average solution GOR for the field is around 1100 scf/stb with an increase in field GOR after 20 years depletion of only 35%. Reservoir compaction has provided a large energy contribution during pressure depletion. Reservoir compaction has been observed by porosity reduction in infill wells and has also resulted in reservoir thickness reduction. Porosity and thickness reduction has been a complicating factor in the geological and rock property modeling. An example of porosity reduction is seen in Figure 12. The porosity reduction is not ‘uniform’ and matching porosity reduction with the rock compaction curve has not been straight forward, Halvorsen [13]. Geomechanical modeling has been useful to assess impact of strain arching and areas with additional strain and hence higher compaction energy. In 2002, the Valhall partnership decided to inject water in order to increase oil recovery. Water injection will start up during 2003, and will initially focus on the crestal parts of the field. There exact incremental recovery from the field is difficult to predict, Martinsen et.al. [14]. The fractures, wettability, relative permeability and low matrix permeability represent a large uncertainty to incremental recovery. Completion History


Initial testing at Valhall gave experiences with severe chalk production and casing deformations due to the weakness of the Tor formation. It was apparent that completion design would be a critical factor to successfully produce the field. The completion strategy has continuously been developed over the years with focus on limiting solids production and well failures. The completion history can be divided into periods as described below. More completion details from 1982 to 1992 are presented by Ali and Alcock [1]. 1980-1985 The first step in developing Valhall was through “Up and Under Fracturing”. The concept was to perforate the more competent upper Hod formation below the weaker Tor and propped fracture stimulate up into the high porosity chalk. This was often combined with direct fracturing into the more competent but less productive Lower Hod formation. This was a success until massive chalk production and well collapses in mid-1985 resulted in drop in field production from around 60,000 to 30,000 BOPD. The technique was reassessed and abandoned for the combination of direct propped fracture stimulation and gravel packing. 1985-1990 The new method called “Propped Fractured Gravel Packs” consisted of 180o phasing perforations that were propped fracture stimulated using a Tip Screen-Out design, Smith et. al. [15], followed by an internal gravel pack operation , Attard et. al. [16]. The gravel pack was designed to support the weak chalk and was successful in reducing massive chalk influxes and well failures. This was the general completion method until problems started to materialize from 1990. This led to the use of resin-coated proppant directly fractured into Tor but with no gravel pack. This was reasonably successful combined with an increasing awareness of proper choke control. 1990-1995 The first horizontal well was drilled in 1990/91 after reservoir studies and simulations indicated increased recovery and higher flow rates at lower drawdowns. However, the theoretical performance of horizontal wells turned out to be too optimistic for a stress sensitive reservoir as the Tor chalk, especially as a dramatic increase in well failure frequency was seen. In the first years, one did typically loose access to 80% of the horizontal section within the six first months on production. The reason was chalk production and deformed/collapsed liners. A variety of completion and stimulation methods were used as described below: Acid Fractured Horizontal Wells The first horizontal well was acid fracture stimulated with HCl. Acid fracturing had been tried out on the flanks with acceptable results in the late eighties. Initial performance was good, but with steep decline as fractures started to close. The Lower Hod formation was also acid fracture stimulated, a method still used. Initial rates of 10,000 BOPD declining to 3-

4,000 BOPD within two months are typical, but with positive response to re-stimulations. Acid Matrix Stimulated Horizontal Wells These wells were performed in order to ensure that drilling mud damage was properly removed from the natural fractures. The acid was pumped below fracturing pressure, performance was believed to be similar to a cased-off openhole well, and a directly perforated unstimulated well. Direct Perforated Unstimulated Horizontal Wells These wells showed that it was possible to produce the Tor formation through unstimulated perforations at economical rates. Cased-off Openhole with External Casing Packers. This well completion was developed in order to try an openhole completion type at Valhall. The mud cake was removed using a mud breaker fluid before possibly unstable zones were isolated using external casing packers (ECP). The liner was then perforated and the well put on production. Based on the experience with these wells, low cost openhole completions were evaluated, Kristiansen [17], and tested out successfully in a Tor well in 1996. The productivity from this well was, however, low. 1995 to 2003 Due to the relatively disappointing performance of the horizontal wells, studies were initiated to investigate root causes of the behavior, Kristiansen [18] and Kristiansen and Meling [19]. The aim was to develop a cost effective and stable completion while producing at economical rates from a large drainage area. The developed concept was a horizontal cased hole completion with multiple propped fractures with the first well (A-4 B) completed in 1995, Norris et. al [20]. The wells were usually equipped with heavy walled (HW) liners (6-5/8”/66 lb/ft or 5-1/2”/46 lb/ft) and perforated with 180o phasing to improve wellbore strength and stability, Pattillo and Kristiansen [21]. To date there are no clear evidence of deformed or collapsed HW liners in the reservoir. The number of zones has varied from 3 to 12. The proppant clean-outs and zonal isolation were initially carried out using snubbing, but this method was soon replaced by coiled tubing. This method is still the preferred completion and stimulation method used for horizontal Tor wells today, Olson et. al [22]. Clean out of excessive proppant and perforating is conducted on the same coiled tubing run and sand (proppant) plugs are used for zonal isolation, Norris et. al. [23]. This reduces the cycle time per propped fracture down to an average of 3 days and most of the excessive proppant is recycled, Slater [24]. The benefits from these completions have been high and sustained rates, typically producing 5 to 8,000 BOPD the first year. Stability has generally been good, but some solids production and chalk influxes are still experienced.


Well failures and well management The weak reservoir formation represented a key pre-development issue. Laboratory tests indicated possibilities for the chalk to flow as “toothpaste” under certain conditions, resulting in casing deformations and collapse. And the development of the field has in fact been a continuous struggle aiming for completion techniques that would allow sustained high oil rates without producing chalk. The economic impact has been significant, but today’s improved completion techniques combined with proactive well management has resulted in a significant more stable production. There are two types of well failures: 1. Influx failure - reservoir chalk is produced in an

uncontrolled way into the wellbore. The result is plugged off wellbore. Chalk influx is evidently linked to pressure cycling and total draw down of the reservoir. Production may be restored by coiled tubing cleanout, taking about 1 week and at a cost of 400 MUSD.

2. Terminal failure - production may not be restored due to lack of access, and the well has to be sidetracked at a cost of 10 - 20 MM USD. During the first ten years of production, the reason was usually a collapsed casing or liner at top reservoir level, usually at the perforations. Today most failures appear to occur close to faults in the overburden that may be re-activated because of subsidence. The re-activation is seen as micro-seismic events and the casing design has been modified in order to accommodate shearing, Kristiansen et. al [25].

The first horizontal wells drilled in the early nineties were severely plagued by well failures, Figure 13. This resulted in a strong focus on well management and triggered several new initiatives, Kristiansen [17] and Kristiansen and Meling [18]. More resources were assigned to well management, including a dedicated well management engineer onshore and soon in rotation with petroleum engineers offshore. The purpose was to train and transfer experience to offshore production staff. Detailed opening and shut down guidelines were developed for each well and the offshore control system was refined to accommodate use of remotely operated chokes. The new chokes made it easier to handle the wells more smoothly by control room operator while monitoring the well performance. Acoustic sand detectors were mounted on critical propped fracture stimulated wells, as flow of proppant may easily be detected. The focus continues today. A dedicated control room operator monitors the wells continuously offshore. Alarms are triggered if pressure drops below predefined limits and action taken. In addition, a full time onshore well engineer monitors well performance and provides guidelines to the offshore staff. A duty roster system with a pool of petroleum engineers ensures follow up and well monitoring coverage outside office hours.

Detailed well guidelines defining draw down schedules and opening guidelines for new wells are issued weekly. As a result, a horizontal acid fracture stimulated well in the Lower Hod formation is typically not fully open after 3-4 months. A horizontal multiple propped fracture stimulated Tor well will normally require a year to be producing at separator pressure, Figure 14. The schedule very much depends on stability, solids production, completion quality, reservoir properties and response. The strategy is to draw the wells down quite quickly the first days in order to clean up the fractures and then gradually slow down. Compaction and Subsidence A major issue arising from testing reservoir cores in the laboratory was what magnitude of compaction and related permeability decline to be expected for the field, and whether the compaction would be reflected as seafloor subsidence. Seafloor subsidence was measured in 1985 only 3 year after production start-up and was found to be around 0.5 meters. Since then, the subsidence of the platforms at Valhall has been measured with pressure gauges at the seafloor, infrared sensing, single frequency GPS and currently dual frequency GPS. Figure 15 shows the subsidence data at Valhall from the initial measurements and until today. One can observe a relatively constantly subsidence rate around 25 cm/year. The reason for the subsidence is the reservoir compaction, which is transferred through the overburden and up to the seafloor as subsidence. The large amount of seafloor subsidence as observed at Valhall can be attributed to the high initial porosity of the chalks. The high initial porosity in the field is primarily caused by the overpressure, secondary by early oil migration, which would reduce any diagnesis as well as chalk water weakening. The crestal Tor reservoir was around 2900 psi over pressured at discovery. This is with a pore pressure of 6550 psi and an overburden of around 7200 psi. This effective stress (650 psi) felt by the matrix is equivalent to a burial depth of only 700-800 meters. Core with porosity in the excess of 53% has been recovered from the field; log porosity can locally be higher. When a weak chalk like this is buried to around 2450 meters, but is only loaded with an effective stress, which is equivalent to, a burial depth of 700-800 meters one will expect the chalk to compact and lose the porosity rapidly as the pore pressure is depleted by 4500 psi and even more close to the wells. This extreme porosity reduction is indeed taking place in the Valhall reservoirs. It can be observed in wells instrumented with radioactive bullets and logged periodically in order to measure formation strain. The chalk in the Tor formation at Valhall is very clean (96 to 98% calcite). The chalk is composed of coccolith fragments of around 0.5 to 1 micron in size. A large number of these coccolith fragments are still parts of intact rosettes or parts of rosettes. The size of these rosette fragments can be tens of microns. Compaction in itself is just a process where the initial


open pore space is reduced through a deformation of the fine-grained structures into the very open pore space in these highly porous chalks. Due to the very complicated microstructure, the chalks are very strain rate sensitive materials. The measured stiffness and deformations are strain rate dependent. Deformations at constant stress also show a logarithmic creep response. This strain rate dependent deformation makes the prediction of deformations over long periods a bit uncertain from a few weeks of creep tests in the laboratory. Ruddy et. al [26], Andersen et. al [27] and Andersen [4] discuss the strain dependency of chalk in detail. A stress-strain diagram of some typical Valhall chalk specimens is shown in Figure 16. One can see that the strain response is characterized with a close to elastic response at low stress levels, then the chalk yield and is going through a transition before the sample starts to deform plastically with some signs of hardening. The curves for similar porosity are equal. The curves for specimens with similar porosity, but with water as the pore fluid, are showing a much weaker and softer response. This is due to the water weakening effect in chalk , Andersen et. al [28] Andersen [4] and Risnes et. al [29]. The results from compaction at Valhall are both positive and negative. The positive effects like reservoir drive energy are far outweighing the negative ones, like chalk production and influx failures and well failures. Modeling of compaction is currently done using two separate numerical models. In the reservoir fluid flow model, the laboratory stress-strain curves have been adjusted for the strain rate difference between the laboratory and the field and converted to pore volume multiplier look-up tables as a function of reservoir pressure. In the compaction and subsidence model in ABAQUS, Pattillo et. al [30], the chalk is modeled with a more accurate constitutive model. The latter models have most of the time been run with the pore pressure history from the fluid flow models as input to the deformation analysis. Recent closer coupled fluid flow and deformation models indicate that this approach may be too simplistic and therefore producing less accurate results than a fully coupled model. One of the challenges in terms of modeling the fluid flow in the Valhall reservoir has been to get the compaction energy right. This has historically been partially due to lack of relevant up-scaling from intact laboratory specimens to larger reservoir grid cells containing high number of fractures. Other problems are related to the size of the deformations in the reservoir and the fact that the standard reservoir flow simulation tools in the oil industry is not able to handle load transfer within the reservoir or from one reservoir area to another via the overburden. This problem can be illustrated by the results from a recent compaction and subsidence model run with the ISAMGEO software showing the magnitude of the vertical stress (overburden) across the field at a specific point in time. These results are seen in Figure 17 and one can

observe quite rapid local variations of around 450 psi in difference. This implies that the standard reservoir flow model is using the same pore volume reduction for a given pore pressure even if the effective stress can be 450 psi different. In addition to the load/stress transfer limitations in the standard flow models, the limited coupling between pore pressure and deformation in the standard flow models will also make the prediction of accurate reservoir pressure in a low permeable highly compressible reservoir very challenging. In some situations, the compaction and subsidence process will generate areas in the chalk reservoir that is actually increasing in pressure during depletion, Cuisiat et. al [31]. This is captured in the fully coupled simulation with VIRAGE, which is compared to a standard ECLIPSE run in Figure 18 for a local Valhall model. Water induced chalk weakening during waterflood is a phenomenon, which has been discussed in the literature the last ten years. The effect was pointed out by Andersen et. al [27]. It is clearly seen in Ekofisk, Sylte et. al [32]. The exact mechanism for the chalk weakening has not been isolated, but several authors have suggested a pure capillary effect. In recent work, Risnes et. al [29] suggest a physio-chemical process where the most important mechanisms are due to absorption pressure and pressure solution. The full field water flood will not start until 4Q 2003. Initially, A simplistic function based on initial interpretations of the laboratory tests was implemented in the standard flow model to take into account the water induced rock compaction, Cook et. al [33]. Later laboratory results have resulted in refinements of this functionality. Water-induced compaction is not a function of initial porosity only, but also initial water-saturation and the relative change of the water saturation. It is expected that the fully coupled models under construction will be more effective in also handling the water weakening process. Waste Injection Waste injection trials were initiated in the late eighties and proved economically rational in connection with stricter environmental legislation to be implemented in 1993. Regular waste disposal started up in 1992 and to date more than 9 MM bbls have been injected downhole at Valhall. The early experience and theoretical basis is described by Moschovidis et. al [34]. An update is also given by Moschovidis et. al [35]. Valhall generates close to 1 MM bbls of waste each year. The largest contribution comes from filter and separator washes from the process plant with drill cuttings slurry being second. The waste is injected in batches of 2-3,000 bbls at rates of 5-8 BPM. A well and volumetric overview is given in Table 1. The first well used, A-20 A, was an old producer transformed to an injector. Waste was pumped through tubing and into the Paleocene shale above the reservoir. The well was re-perforated several times in Paleocene, Eocene and Miocene due to plugging until indications of casing deformation and waste domain being too shallow resulted in sidetracking the


well. In the mean time, shallow annular injection below the 13-3/8” casing shoe in the Miocene was performed in two wells. The sidetracked well, A-20 D, was a splitter well (multi-lateral class 6S) with one producing and one waste disposal leg injecting into Eocene, Sund et. al [36]. Due to temporary integrity problems after a year, the poor producer A-25 B was picked as an additional waste well. Injection was into the Cretaceous reservoir far out on the flank, but pressures gradually rose even above the overburden fracturing pressure in Paleocene. The well is still used today and seismic images have proven the waste to be deposited into the overlying Paleocene shale, see Figure 19. Large volumes have been injected and the waste wells have experienced more integrity problems than producers have. Close monitoring and detailed operational guidelines is critical for managing the waste wells which are needed to support drilling and production activities. Overburden Drilling and Replacement of ERD Wells From the mid-80’ties a number of slanted wells with high inclination were drilled towards the flank of the field. Reservoir characterization indicated that horizontal wells would be needed in order to drain the thinnest areas in the flanks of the field. A record ERD well (A-30B) was drilled to the southern flank of the Valhall field in 1993. The well was proving up substantial reserves in the south flank of the field. The well had a sail angle between 70 and 75 degrees through the shales of the Hordaland Group. The well was not drilled without problems. The clean-out trip prior to running the casing in the 12 ¼” section took close to 750 hours. Several development concepts were evaluated for the producing the flank reserves at Valhall. A wellbore stability study indicated that a solution to go for two satellite platforms in the flanks could be a less risky alternative than a central platform. This was primarily because of two reasons: 1) the safe operational window between the collapse pressure and the frac gradient was indicated to be narrow. 2) There were concerns that the ongoing subsidence could potentially increase the risk during drilling as well as shorter well life on production for ERD wells. The conclusions, however, were based on limited data and quite simplified and uncertain models. After the A-30B well had been drilled it was pointed out that some of the large cavings, which were age dated, was originating from a fault intersection that could be clearly seen based on coherency analysis of the seismic data, Kristiansen [37]. Based on an overall assessment of economics and risk, the concept selected was a wellhead platform with bridge connection to the existing platform complex at Valhall. The oil would be produced with horizontal wells similar to the A-30B well. A steep learning curve was assumed from the drilling of this well. A work program that would assist drilling in reducing risk of “geological related unscheduled events” in the ERD wells was initiated in order to reduce risk. The program looked at integrating seismic, petrophysics and rock mechanics. Examples of some of the integration is presented in papers by Kristiansen [37] and Kristiansen et. al [38].

The work supported the conclusions of the early work. The work indicated a very narrow safe operational ECD window, where some uncertainties were attributed to the potential effect of subsidence. The change in stresses in the overburden as predicted from a full field 3D continuum finite element model (ISAMGEO) is shown in Figure 20. Work in modeling stresses in faults indicated that the local changes around these could be substantial higher than showed in Figure 20. This explained some of the field observations that drilling ERD wells at Valhall was similar to “walking the razors edge”. Only minor incidents could make the well impossible to drill. The “stochastic nature” of drilling the overburden at Valhall with high sail angles is illustrated in Figure 21 and 22. As the sail angle is increased above 55 degrees, the risk of increasing the cost due to unscheduled events increases significantly. Due to the ongoing subsidence process with stress changes and stress release, it was concluded that an exact prediction of drilling conditions pre-drill would be difficult. The trend in the data indicated that the problem was getting worse with time. After only achieving a 25% success rate between 1997 and 2000 for the ERD wells at Valhall, with substantial NPT cost, it was decided that the risk of drilling these wells was too high. This was after an aggressive application of proto-type technology for real-time wellbore stability and control, Bradford et. al [39]. Two unmanned satellite platforms have been constructed in order to access the flank reserves at a lower and more predictable cost. The concept for doing this is illustrated in Figure 23. The implementation of these two platforms will also increase the recovery from the field as well as assisting to keep the field on plateau longer. The learning’s will also be applied in the upcoming water injector wells in the crest of the field 20 Years on Plateau Figure 24 shows the historic production profile for the Valhall field. The history can be split into following stages: 1982-1985 : Build up of production with initial drilling. 1985-1986: Loss of high rate wells due to well failures 1986-1990: Continue drilling with improved completion techniques, drill up remaining slots and add additional 6 slots to the DP platform. 1990-1994: Start drilling horizontal wells and drain thin areas that were uneconomic without horizontal wells. Climb learning curve with implementing and managing horizontal wells including optimized drawdown schedules for individual wells. High well failure frequency was experienced initially, but improved rapidly. 1994-1999: Propped fractured horizontal wells proven as most effective completion technique. Install Wellhead Platform with 19 additional slots. Large infill program arrest field decline and gain rate to 80 M stb/d. 1999-2000: Drilling pause 2000-2003: Arrest field decline by sidetracking failed wells. Developing completion techniques described in previous sections has been vital in the Valhall field management.


Figure 13 shows number of chalk influxes with time. Chalk influxes mean deferred production and costs related to clean out. Well failures are plotted ‘normalized’ to the number of producing wells and Figure 25 shows how this trend peaked in 1992 when horizontal wells were introduced. The well failure frequency has declined as improved completion techniques were developed and through careful well monitoring and drawdown procedures. Terminal well failure remains a challenge. Due to water induced weakening of the chalk, reservoir compaction and seabed subsidence are predicted to continue during injection. Terminal well failures cause high capital expenditures on wells and increases lifting costs. Since 1995, all wells are completed with heavy wall liners in the reservoir section, and this has effectively stopped collapses in the reservoir section with long liner laps. Today nearly all terminal well failures are due to casing failures in the overburden. The strategy to minimize well failures is in the overburden as follows:

• Design well trajectory to avoid large faults in the overburden

• Avoid drilling high angle wells, drain flank areas from the new flank wellhead platforms.

• Casing design to enable some overburden movement. Infill drilling has been key in arresting field decline. With the exception of a few periods with drilling stops, infill wells have been added. Infill wells have further provided reservoir data to improve static and dynamic reservoir model. Continuous improvement in the reservoir model has provided new ‘low risk’ infill opportunities. The long ‘plateau’ period for an oil reservoir on primary, depletion (without a strong aquifer or a gas cap) could not have been achieved without the large rock compaction. The large rock compaction amounts to more than 50% of the reservoir energy. With large rock compaction combined with relatively low gas mobility the recovery factor from primary depletion is estimated in the 33% range. With waterflood scheme as currently planed, the ultimate recovery factor is estimated around 40%. Future Developments In 2003, water injection will start up in the depleted parts of the field. Although core tests have shown promising displacement efficiency, field recovery from water injection is uncertain, Martinsen[13], and Ali et al. [40]. Waterflood is planned with both horizontal injectors and producers. Two additional wellhead platforms have been installed (South and North) and these will provide efficient access to the flank areas. In these areas pressure is still high, and a period of primary depletion will be take place prior to water injection. As part of managing the sweep and to optimize infill drilling, Life of Field Seismic (LoFS) array will be installed over the field, Barkved et. al [41]. This will provide a future foundation

for Valhall reservoir management, and help shaping the future drainage strategy. Future Re-development of Valhall Due to the subsidence, the air-gap for the platforms at Valhall is approaching the limit in terms of what is needed for the 100-year wave. In addition, the facilities are aging, so replacement of these in lieu of the license expiry in 2028 is also more attractive. One of the major uncertainties related to the timing of jack-up of the platforms or building new ones is related to the exact in-situ effect of injecting water into the reservoirs at Valhall. There are some uncertainties related to the geomechanical behavior of the chalk during long time exposure to the seawater in-situ, but really, the largest uncertainty on subsidence and subsidence rates are related to reservoir pressure and saturation changes with a displacement process. This is illustrated in Figure 26 (based on numerical simulations with ISAMGEO), which compares subsidence forecasts for Valhall depending on rock mechanics uncertainties, and pressure and saturation response uncertainties for the flow model. There are two main groups of curves. The two curves indicating subsidence in the 12-13 meter range around 2050 is resulting from a poor displacement process. The difference between these two high curves is illustrating the uncertainty in the rock mechanics (the water weakening effect). The curves predicting lower subsidence are based on a most likely scenario and again the scatter is a result of the uncertainty in the water weakening effect. Conclusions

• The Valhall field has produced for 20 years on primary depletion and recovered to date almost 100% more than the reserves the development was sanctioned on.

• Plateau production around 80M stb/d has been achieved by continuous drilling and large reservoir energy from rock compaction.

• Geosteering has been key to steer horizontal wells in thin reservoir sections, and guide operation decisions on casing points etc.

• Careful well operation procedures have been necessary to minimize solids production and well failures. Wells have individual set opening and shut down procedures with pre-programmed alarm settings and acoustic solids detectors.

• Reservoir compaction and seabed subsidence has caused large drilling challenges in the overburden, particularly Extended Reach Drilling. Infill drilling from Flank Platforms has therefore proven more cost effective to produce downdip reserves.

• Through evolution of completion techniques, propped fractured horizontal wells with heavy wall liners have proven most efficient, and is currently the preferred completion method.

• Pressure depletion, porosity and thickness reduction have given excellent 4D seismic response. 120 km of


permanent seismic cables are being installed this year to monitor changes in seismic response with time.

• Since 1992 all separator washes from solids production and cuttings from drilling have been injected into waste injection wells (a total of 9MM bbls). This method has proved to be safe, environmentally friendly and economic.

• The Platforms have subsided a total of 4.9 m since start of production because of reservoir compaction. Due to water weakening effects on chalk, compaction and subsidence is expected to continue after waterflooding.

• Improved reservoir models have identified many areas of inefficient drainage and field decline has been arrested with infill drilling.

• The Valhall team is challenged to extend the plateau for 10 more years with waterflood and further infill drilling in flank areas.

• Seismic data is critical to successful development of the field. The installation of a permanent seismic array reflects the commitment and expectations to 4D/4C seismic to shape the future depletion strategy

• Total estimated reserves are over 4 times initial (PDO) estimate (Figure 27).

Acknowledgment The authors wish to thank the Valhall partnership (BP Norge, Norske Shell, Total E&P Norge and Amerada Hess Norge for permission to publish this work. The results and opinions presented in this paper do not necessarily reflect the view of the Valhall partnership. References [1] Ali, N. and Alcock, T.: “Valhall Field, Norway – The First Ten

Years,” North Sea Oil and Gas Reservoirs – III, NTH: 1994, 25-40.

[2] Farmer, C. L. and Barkved, O.I., 1997. Influence of syn-depositional faulting on thickness variations in chalk reservoirs – Valhall and Hod fields. Petroleum Geology of Northwestern Europe: Proceedings of the 5th Conference. Geological Society of London.

[3] Mann, K. O. and Lane, R., 1995. Graphic Correlation, SEPM Special Publication No. 53.

[4] Andersen, M.A.: “Petroleum Research in North Sea Chalk”, monograph, 1995, Rogaland Research

[5] Powley K.D, Peng C.P. and Ali N: “Simulation of a North Sea Chalk Reservoir with Dynamic Rock and Natural Fracture Properties: Case Study of the Valhall Field” (SPE 24914)

[6] Barkved, Successful Use of Seismic Attribute Maps and Post-Stack Inversion In Horizontal Well Planning, 1996, EAGE Expanded Abstracts

[7] Leonard, R.C. and Munns, J. W., 1987. Valhall Field in Geology of Norwegian Oil and Gas Fields, Graham and Trotman, pp. 153-163.

[8] Thomsen, L., O. Barkved, W. Haggard, J. Kommedal and B. Rosland, 1997. Converted Wave Imaging of Valhall Reservoir, EAGE Expanded Abstracts , 59, B048.

[9] Rosland, B. O., Tree, E.L., Barkved, O.I., Kristiansen, P., 1999, Acquisition of 3D/4C OBS data at Valhall, EAGE Expanded Abstracts, 61

[10] Barkved, O.I., Mueller, M.C., Thomsen, L., 1999, Vector Interpretation of the Valhall 3D/4C OBS dataset, EAGE Expanded Abstracts, 61.

[11] Barkved, O., Buer K., Halleland, K.B., Kjelstadli, R.,Kleppan, T., Kristiansen, T.G., 2003, 4D Seismic Response of primary production and waste injection at the Valhall field EAGE Expanded Abstracts.

[12] Hall, S.A., Kendall, J.M., Barkved, O.I., Fractured reservoir characterization using P-Wave AVOA analysis in 3D OBC data, TLE

[13] Halvorsen H.,” Porosity Reduction Measured by Logs in the Valhall Field” – 4th North Sea Chalk Symposium, Sep 1992.

[14] Martinsen, R., Kjelstadli R.M., Ross C., Rostad H. ”The Valhall Waterflood Evaluation: A Decision Analaysis Case Study” (SPE 38926)

[15] Smith, M. B., Miller II, W. K., and Haga, J.: “Tip Screenout Fracturing: A Technique for Soft Unstable Formations”, paper13273 presented at the 1984 59th SPE Annual Technical Conference and Exhibition, Houston, TX.

[16] Attard, M., Mathes, R. A., and Mower, L. N.: “Gravel Packing in an Abnormally Pressured Chalk Reservoir: A Valhall Field Case Study”, paper 18226 presented at the 1988 63rd Annual SPE Conf. Proc. (P- Production Operations and Engineering), Houston.

[17] Kristiansen, T.G.: “Geomechanical Analysis of the Feasibility of Openhole Completions in the Weak, Plastic Tor Formation at Valhall, Based on Numerical Modeling, Analytical Analysis and Field Data” paper presented at Fifth North Sea Chalk Symposium, October 7-9, 1996, Reims, France.

[18] Kristiansen, T.G.: “A Review of Completion Techniques and the Impact of Geomechanical Processes on their Performance in the Valhall Field”, paper presented at Fifth North Sea Chalk Symposium, October 7-9, 1996, Reims, France.

[19] Kristiansen, T.G. and Meling, S.: “A Production Parameter Analysis of Chalk Influxes in the Valhall Field”, paper presented at Fifth North Sea Chalk Symposium, October 7-9, 1996, Reims, France.

[20] Norris M.R., Berntsen B., Myhre P. and Winters W: “Multiple Proppant Fracturing of a Horizontal Wellbore: an integration of two technologies,” paper SPE 36899 presented at the 1996 European Petroleum Conference, Milan, Italy, October 22-24.

[21] Pattillo, P. D., and Kristiansen, T. G.: “Analysis of Horizontal Casing Integrity in the Valhall Field”, SPE/ISRM 78204, SPE/ISRM Rock Mechanics Conference held in Irving, Texas, 20-23 October 2002.

[22] Olson K.E., Olsen E., Haidar S., Boulatsel and Brekke K.: “Valhall Field: Horizontal Well Stimulations ‘Acid vs. Proppant’ and Best Practices for Fracture Optimization,” paper SPE 84392 to be presented at the 2003 SPE Annual Technical Conference an Exhibition, Denver, Colorado, U.S.A., October 5-8.

[23] Norris M.R., Berntsen B.A., Skartveit L. and Teesdale C.: “Multiple Proppant Fracturing of Horizontal Wellbores in a Chalk Formation: Evolving the Process in the Valhall Field,” paper SPE 50608 presented at the 1998 European Petroleum Conference, The Hague, The Netherlands, October 20-22.

[24] Slater M., Perez D., Teesdale C. and Hilbig N.: “Unique Offshore Recovery System Dramatically Reduces Environmental Impact by Recycling Stimulation Proppant,”


paper SPE 74473 presented at the 2002 SPE/IADC Drilling Conference, Dallas, Texas, U.S.A., February 26-28.

[25] Kristiansen, T. G., Barkved, O., and Pattillo, P. D.: “Use of Passive Seismic Monitoring in Well and Casing Design in the Compacting and Subsiding Valhall Field, North Sea”, SPE 65134, presented at the SPE European Petroleum Conference held in Paris, France, 24–25 October 2000.

[26] Ruddy, I., Andersen, M.A., Pattillo, P.D., Bishlawi, M., and Foged, N.: "Rock Compressibility, Compaction, and Subsidence in a High Porosity Chalk Reservoir: A Case Study of Valhall Field", Journal of Petroleum Technology, July, 1989, pp. 741-746.

[27] Andersen, M. A., Foged, N., and Pedersen, H.F.: ”The Rate Type Compaction of a Weak North Sea Chalk”, paper presented at the 1992 33rd US Symposium on Rock Mechanics, Santa Fe, NM. Balkema

[28] Andersen, M.A., Foged, N., and Pedersen, H.F.: ”The Link Between Waterflood-Induced Compaction and Rate-Sensitive Behavior in a Weak North Sea Chalk”, paper presented at te 1992 Fourth North Sea Chalk Symposium, Deauville, France.

[29] Risnes, R., Hole, M., and Kwabiah, N.K.: “Chalk-fluid Interactions with Water-Glycol Mixtures”, paper in the press.

[30] Pattillo, P.D, Kristiansen, T.G., Sund, G.V., and Kjeldstadli, R.M.: “Reservoir Compaction and Seafloor Subsidence at Valhall”, paper (SPE/ISRM 47274), Proc., Eurock ‘98, Trondheim, Norway, 1998.

[31] Cuisiat, F., Gutierrez, M., Lewis, R.W., and Masters, I.: “Petroleum Reservoir Simulation Coupling Flow and Deformation”, (SPE 50636), 1998

[32] Sylte, J.E., Thomas, L.K., Rhett, D.W., Bruning, D.D., Nagel, N.B.; “Water Induced Compaction in the Ekofisk Field”

[33] Cook, C., Andersen, M.A., Halle, G., Gislefoss, E., and Bowen, G. R.: ” Simulating the Effects on Water-Induced Compaction in a North Sea Reservoir”, paper, SPE 37992, presentation at the Reservoir Simulation Symposium held in Dallas, Texas, U.S.A., 8-11 June 1997.

[34] Moschovidis, Z.A. , Gardner, D.C., Sund, G.V.: “Disposal of Oily Cuttings by Downhole Periodic Fracturing Injections in Valhall-North Sea: A Case Study and Modelling Concepts,” paper SPE/IADC 25757 presented at the 1993 SPE/IADC Drilling Conference, Amsterdam, February 23-25.

[35] Moschovidis, Z.A., Kleppan T. and Kristiansen T.G.: “Evaluation of Cuttings Injection in A-20 D Splitter Well in Valhall,” paper presented at the 6th International Conference on “Minimising the Environmental Effects of Drilling Operations”, Aberdeen, Scotland, June 18-19, 1998.

[36] Sund, G.V., Wenande B., Weaver C.L. and Adams J.M.: “Downhole Splitter Well for Simultaneous Injection and Production at the Valhall Field,” paper SPE 38498 presented at the 1997 Offshore Europe Conference, Aberdeen, Scotland, September 9-12.

[37] Kristiansen, T. G.: "Geomechanical Characterization of the Overburden Above the Compacting Chalk Reservoir at Valhall," paper (SPE/ISRM 47348), Proc., Eurock ‘98, Trondheim, Norway, 1998.

[38] Kristiansen, T.G., Mandzuich, K., Heavey, P, and Kol, H.: “Minimizing Drilling Risk in Extended-Reach Wells at Valhall Using Geomechanics, Geoscience and 3D Visualization Technology”, SPE/IADC 52863, presented at the 1999 SPE/IADC Drilling Conference, Amsterdam, 9-11 March, 1999.

[39] Bradford, I. D.R., Aldred, W.A., Cook, J.M., Elewaut, E.F.M., Fuller, J.A., Kristiansen, T.G., and Walsgrove, T.R.: “When Rock Mechanics Met Drilling: Effective Implementation of

Real-Time Wellbore Stability Control”, SPE 59121, presented at the 2000 IADC/SPE Drilling Conference held in New Orleans, Louisiana, 23-25 February 2000.

[40] Ali, N, Singh P.K, Peng C.P., Shirlakar G.S., Moschovidis Z, Baack W.L. “ Injection Above Parting Pressure Waterflood Pilot Valhall Field” (SPE 22893).

[41] Barkved, O., Bærheim A.G., Howe,D.J., Kommedal, J.H., and Nicol, G.,Life of Field Seismic Implementation - "First at Valhall" – Workshop Notes EAGE 2003.

Tables Table 1: Valhall Field, pertinent data sheet Discovery 1975 First Production October 1982 Water depth, (m) 69 Reservoir depth, (m) 2400-2600 Initial Reservoir Pressure (psi) 6550 Reservoir Temperature (deg C) 90 Oil gravity, (API) 36 Oil viscosity, (cp) 0.40 Original oil-in-place, (MM stb) 2600 Cumulative oil production jan 2003, MM stb)

472

Average thickness, (m) 25 Matrix Permeability range, (mD) 1-10 Total Permeability range, (mD) 1-300 Connate water saturation, (%) 5 Porosity, (%) 35-50 Bubble point pressure, (psi) 3000-4000 Solution GOR (scf/stb) 800-1400 Rock Compressibility (10-6 psi-1) 10-100 Table 2: Overview of waste disposal wells and injected volumes.

Well Injection Domain Depth Av. batch Cum.into (m TVD) volume volume

(bbls) (bbls)A-20 A Tubing Shale / 1590-2457 1965 3 449 269

Overburden

A-16 D Annulus Shale / 1362 2170 219 637

Overburden

A-3 B Annulus Shale / 1242-1251 2382 574 102

Overburden

A-20 D Tubing Shale / 2183-2188 2182 2 581 321

A-25 B Tubing Chalk / 2611-2633 2597 2 470 262

Reservoir

Total 9 294 591


V ALHALL

ST A V ANGER

0 100 km

UNITED KINGDOM

NOR W A Y

GERMANY

DENMARK

UNITED KINGDOM

GERMANY

DENMARK

NOR W A Y

0 100 km

HOD

Figure 1: Location of the Valhall field in the Norwegian sector of the North Sea.

Figure 3: Simplified reservoir zonation from the Valhall field

Figure 4: Cross - section across the Valhall Field. See figure 2 for location.

N

TIME MAP TIME MAP

?

N N

TIME MAP TIME MAP

?

Figure 5: Well planning using existing drilling observations posted as symbols, combined with faults from seismic in a 3D representation.

Figure 6: The presence of a low velocity gas-charged Miocene diatomaceous interval creates a "gas cloud" effect that distorts the seismic time data.

2/7 2/8

30 20’

10.000 m.

560 15’

2/11

2 3 0 0

2 4 0 0

2 5 0 0

2 6 0 0

2 7 0 0

2 8 0 0

2 9 0 0

3 0 0 0

V a l h a l l F i e l d C r e s t a l A ́ E a s t A

W e s t

S k e t c h N o t t o s c a l e V e r t i c a l

E x a g g e r a t i o n x 1 0

L . C r e t a c e o u s L o w e r H o d

L i s t a F m

T o r F m

O W C L .

H o d O W C T o r

L o w e r H o d F m

C h a l k G r o u p

2 3 0 0

2 4 0 0

2 5 0 0

2 6 0 0

2 7 0 0

2 8 0 0

2 9 0 0

3 0 0 0

V a l h a l l F i e l d C r e s t a l A ́ E a s t A

W e s t

S k e t c h N o t t o s c a l e V e r t i c a l

E x a g g e r a t i o n x 1 0

L . C r e t a c e o u s L o w e r H o d

L i s t a F m

T o r F m

O W C L .

H o d O W C T o r

L o w e r H o d F m

C h a l k G r o u p

X X’

Figure 2: The Valhall field is a double plunging NNW-SSE trending anticline. Modified from Farmer and Barkved [2].


Figure 7: Seismic attribute indicating distribution of optimal reservoir properties (pink) draped over the Valhall structure. Green colors indicates poor or non reservoir properties.

Figure 8: Use of C- waves (P-waves converting to sheare waves at target reflector) has improved the definition of top reservoir below the gas cloud.

P-Wave Section (Geophone Z) C*-Wave section (Geophone Z)

Figure 10: Shear wave splitting effects (magnitude and strength – orientation and length of vectors) posted on map reflecting subsidence which is up to 3.5 m since 1982.

Reduced Response due to the ” gas cloud ”

Reduced Response due to the ” gas cloud ”

Figure 9: Difference in seismic response between surveys acquired in 1992 and 2002. Bubbles indicate relative productions volumes. The colors inside the circle represent the phase of fluid produced. Green is oil, water is blue and gas is red. From Barkved et.al. [11]

0 200 400 600 800

1000 1200 1400 1600

sep.82 sep.86 sep.90 sep.94 sep.98 sep.02

GO

R s

cf/s

tb

Figure 11: Field GOR

1800


0,37

0,39

0,41

0,43

0,45

0,47

0,49

Por

osity

Compaction Curves

Log data

Reservoir Pressure (psi) Figure 12: Porosity Reduction seen on logs

0,35 5500 6500 1500 2500 3500 4500

Figure 15: Subsidence measurement at Valhall. Subsidence March 2003 was 4.91 m.

0 2 4 6 8

10 12 14

0 20000 40000 60000 80000 100000 Axial stress (kPa)

Axial strain (%)

Base curve(1), Sw=5%,ø=0.46 Base curve(6), Sw=5%, ø=0.42 Base curve(14), Sw=2%,

ø=0.36

0 5

10 15 20 25

0 20000 40000 60000 80000 100000 Axial stress (kPa)

Axial strain (%)

Base curve(1), Sw=5%,ø=0.46 Waterflooding(2), ø=0.47 0 2 4 6 8

10 12 14 16 18 20

0 20000 40000 60000 80000 100000 Axial stress (kPa)

Axial strain (%)

Base curve(6), Sw=5%, ø=0.42 Waterflood(7), ø=0.41 Waterflood(8), ø=0.42

0 2 4 6 8

10 12 14 16

0 20000 40000 60000 80000 100000 Axial stress (kPa)

Axial strain (%)

Base curve(14), Sw=2%, ø=0.36 Waterflood(13), ø=0.34 Waterflood(15), ø=0.37

Creep period

Φ = 36% Φ = 42%

Φ = 46% Waterflooding

Creep period &

Waterflooding Creep period

& Waterflooding

Φ = 46%

Φ = 42% Φ = 36%

Figure 16: Laboratory stress-strain curves comparing Chalk with different porosity and low watersaturation (upper left) to similar specimens injected with water (three next figures). These stress-strain curves are showing how chalk creeps and how it responds to water.

Figure 17: Calculated changes in vertical stress (“stress arching”) between production start-up in 1982 and June 1999 in the Tor M1 layer. The Difference is +/- 1.5 MPa (218 psi) over fairly short distances.

0

2

4

6

8

10

12

14

1982 1986 1990 1994 1998 2002 YEAR

Influx Failures Terminal Failure

NU

MB

ER

OF

FA

ILU

RE

S

.

Influx Failure Well plugged with solids. Returned to production after clean out.

Terminal Failure Casing collapsed. Well could not be returned to production.

Figure 13: Well failure statistics from startup in 1992.

0

500

1000

1500

2000

2500

3000

3500

4000

0 200 400 600 800 1000 Days

Bot

tom

Hol

e D

raw

Dow

n (p

si)

,

Figure 14: Typical bottom hole draw down development in horizontal propped fracture stimulated wells where max is reached after one year or with fully open chokes.


Decoupled Fully - Coupled

VIRAGE

CONVENTIONAL ECLIPSE

Figure 18: Comparison of the conventional ECLIPSE fluid flow model and the fully coupled VIRAGE simulator. Plot to the left show a decoupled run with VIRAGE give the same result as ECLIPSE. Plot show when a fully coupled stress-strain and fluid flow formulation is used. The difference in pore pressure prediction is more in line with field observations at Valhall.

Figure 19: Seismic 4D data showing how the waste injected ino well A-25B is accumulating in the Lista shale formation above the injectin points in the Tor chalk.

Changes at Lista Levels

1992 2002

Figure 20: The change in stresses in the overburden as predicted from a full field 3D continuum finite element model.

Figure 21: Days spent on drilling the Eocene section at Valhall versus year drilled.

0,0 10,0 20,0 30,0 40,0 50,0 60,0 70,0 80,0 90,0

100,0 110,0 120,0 130,0

1986 1990 1992 1992 1994 1994 1995 1996 1996 1996 1997 1997 1998 1998 1999 1999 1999 2000 Year

Days

Successful Unsiccessful Figure 22: Plot of days spent drilling the Eocene section at

Valhall versus sail angle. Square points indicate wells that did not make it to the reservoir.

0 20 40 60 80

100 120 140

0 10 20 30 40 50 60 70 80 Sail angle at 2000-2200m TVD

Day

s

Unsuccessful Successful


Figure 26: Comparison of several subsidence predictions. Run VATL and VATK is showing a worse case scenario in terms of water displacement mechanisms in the reservoir. The difference between the two is uncertainty in the water weakening response of the chalk. The cases VASR (1 and 2) and VASO is using the most likely pressure scenario and different assumptions with regard to the water weakening response of the chalk.

Figure 23: Illustration of the concept of moving surface locations to the flank of the Valhall field in order to improve drilling efficiency and reduce risk of wellbore instability and casing collapse.

Crestal Platform Flank

Platform Flank Platform

Compaction Bowl

0

20000

40000

60000

80000

100000

120000

sep.82 sep.86 sep.90 sep.94 sep.98 sep.02

oil r

ate

(100

0 st

b/d)

Figure 24: Production Profile

Figure 27: Reserve Increase

Reserves MMSTB of Oil

247 247 247 325

380 517 519 519

594 621 667

0 100 200 300 400 500 600 700 800

1986 198

7 1988 198

9 1990 199

1 1992 199

3 1994 199

5 1996 199

7 1998

PDO Reserves

Updated Reservoir

Descr .

5 add' slot approved

Updated Res.

South Flank Pot. &

Waterflood

Pilot

WP Platform w/ 19 Slots Approved

2/8F -

2 proves up new area

Model HM

-

Better Performance

1999

706

New Sw

function and increased STOOIP

200 0

900 1000

License extension Waterflood 5 1

1 82 939

2001

1 1 00 1 2 00

64 45

1048 Flank – North & South Re

serves MMSTB of Oil

0 100 200 300 400 500 600 700 800

1986 198

7 1988 198

9 1990 199

1 1992 199

3 1994 199

5 1996 199

7 1998

PDO Reserves

Updated Reservoir

Descr .


South Flank Pot. &

Waterflood

Pilot


2/8F -


Model HM

-

Better Performance

1999

New Sw


200 0

900 1000

Waterflood

2001

1 1 00 1 2 00

Flank

North & South

Horizontal wells

Reserves MMSTB of Oil

247 247 247 325

380 517 519 519

594 621 667

0 100 200 300 400 500 600 700 800

1986 198

7 1988 198

9 1990 199

1 1992 199

3 1994 199

5 1996 199

7 1998

PDO Reserves

Updated Reservoir

Descr .


Updated Res.

South Flank Pot. &

Waterflood

Pilot


2/8F -


Model HM

-

Better Performance

1999

706

New Sw


200 0

900 1000

License extension Waterflood 5 1

1 82 939

2001

1 1 00 1 2 00

64 45

1048 Flank – North & South

Res

erve

s M

MS

TB

of

Oil

0 100 200 300 400 500 600 700 800

1986

1987

1988

1989

1990

1991

1992

1993

1994

1995

1996

1997

1998 PD

O R

eser

ves

Upd

ated

Res

ervo

ir De

scr .

5 ad

d' sl

ot a

ppro

ved

Sout

h Fl

ank

Pot.

& Wa

terf

lood Pilo

t

WP

Plat

form

w/ 1

9 Sl

ots

App

rove

d 2/

8F - 2 p

rove

s up

new

are

a M

odel

HM

- Bet

ter P

erfo

rman

ce

1999 N

ew Sw

funct

ion

and

incr

ease

d ST

OO

IP

2000

900 1000

Wat

erflo

od

2001

1 1 00 1 2 00

Flan

k Nor

th &

Sou

th

Hor

izon

tal w

ells

Figure 25: “well failure frequency”: Plott showing the well failure frequency on Valhall since start-up in 1982. It is number of influx and terminal well failures per year divided by number of wells. It seems clear the trend is very positive since 1993.

0 0,1 0,2 0,3 0,4 0,5 0,6 0,7 0,8

1982

1984

1986

1988

1990

1992

1994

1996

1998

2000

2002 W

ell F

ailu

re F

requ

ency

(fa

ilure

s/w

ell/y

ear)

,

SPE 83957 Valhall Field - Still on Plateau after 20 Years of Production

Documents

Transcript of SPE 83957 Valhall Field - Still on Plateau after 20 Years of Production