One of the biggest challenges in designing squeeze treatments is ensuring appropriate chemical placement along the completion interval. Generally, the chemical slug is bull-headed; therefore, in long horizontal wells and/or crossflow wells, exposing the chemical to all the completion intervals might be difficult. In this paper we introduce a method to evaluate placement efficiency. If placement is inadequate, some sections of the well will be unprotected, resulting in an undesirable situation: the well may appear to be protected because the inhibitor return concentrations measured at surface are above the threshold, but there is a loss of production due to scale deposition in areas of the well not contacted by chemical. In these circumstances inhibitor placement can be accurately determined by production logging, but this can be prohibitively expensive. An alternative is to use tracers to evaluate the layer flow rate distribution, and therefore quantify chemical placement. The objective of this paper is to determine if a tracer package could be deployed as part of a squeeze treatment in challenging wells, in particular in the overflush stage. If there are zones in the wellbore at different pressures, then producing the tracer back in steps at different rates will result in the tracer return concentration profile having characteristic features that can be interpreted to estimate chemical placement.
Two three layer cases with crossflow are considered. In both cases, a tracer package was included in the overflush, and the resulting return profiles showed clearly the desired features. The main advantage of this approach is that there is no significant increase in the operational expense. The only additional expense will be the cost of the specific tracer and the subsequent analysis. It is envisaged that the cost is less than 5% of the total squeeze treatment cost. The results of this novel multi-rate post squeeze production stage following injection of tracer demonstrate the feasibility of including such a tracer package in a squeeze treatment. Data collected may then be used to optimise the design of subsequent treatments, to ensure that appropriate placement is achieved by rate control or by diversion, if necessary.
In the United Kingdom Continental Shelf (UKCS), a significant heavy oil prize of 9 billion barrels has been previously identified, but not fully developed. In the shallow unconsolidated Eocene reservoirs of Quads3 and 9, just under 3 billion barrels lie in the discovered, but undeveloped fields, of Bentley and Bressay. Discovered in the 1970s, they remain undeveloped due to the various technology challenges associated with heavy oil offshore and the presence of a basal aquifer. The Eocene reservoirs represent significant challenges to recovery due to the unconsolidated nature of the hydrocarbon bearing layers. The traditional view has been that such a nature represents a risk to successful recovery due to sand mobility; reservoir and near wellbore compaction; wormhole formation; and injectivity issues.
We propose improving the ultimate oil recovery by a combination of aquifer water production and compaction drive. By interpreting public domain data from well logs, the range of geomechanical properties of Eocene sands have been determined. A novel approach to producing the heavy oil unconsolidated reservoirs of the UKCS is proposed by producing the aquifer via dedicated water producers situated close to the oil-water contact. The location was determined by sensitivity analysis of water producer location and production rates. By locating water producers at the OWC with a production rate of 20,000 bbls/day of fluids, the incremental recovery at the end of simulation is increased by 4.1% OOIP of the total modelrelative to the ‘no aquifer production’, casesuggesting a significant increase in recovery can be achieved by producing the aquifer. A rate of 30,000 bbld/day located at the OWC was found to increase incremental recovery by 5.8 %OOIP relative to the ‘no aquifer case’. In all cases, as the reservoir fluid pressure is reduced, oil recovery increases via compaction and reduced water influx into the oil leg. This reduced pressure leads to a higher tendency towards reservoir compaction which is expressed as a change in mean effective stress and porosity reduction.
da Fontoura, S. A. B. (Pontifical Catholic University of Rio de Janeiro) | Inoue, N. (Pontifical Catholic University of Rio de Janeiro) | Righetto, G. L. (Pontifical Catholic University of Rio de Janeiro) | Lautenschläger, C. E. R. (Pontifical Catholic University of Rio de Janeiro)
ABSTRACT: The presence of faults is expected to affect the flow of fluids through areas of the reservoir and to have an effect on the mechanical behavior of the reservoir itself. It is a known fact that hydrocarbon production and fluid injection into the earth crust may induce seismicity and undesired reservoir fluid leakage due to localized movements along faults. The behavior of a fault zone depends on the stresses acting upon it and the stresses do change during reservoir production. This paper discusses the mechanical and hydraulic properties of fault zones within petroleum reservoirs. Initially a discussion of fault zone architecture is presented and this architecture is the result of the rock failure process. It follows a discussion on the hydraulic properties of fault zones. Next, a review on the mechanical properties is presented describing how the properties can be estimated. In the end, we offer suggestions on how to couple the hydromechanical processes in order to evaluate the possibility of fault reactivation.
The presence of faults is expected to affect the flow of fluids through areas of the reservoir and to have an effect on the mechanical behavior of the reservoir itself. During hydrocarbon production, fluid withdrawal and injection may cause displacements and strains along the faults present in the reservoir that may be responsible for the loss in reservoir sealing and some minor earthquakes.
Seismicity associated with high pore pressures resulting from fluid injection at depth has been registered in several cases (Healy et al. 1968, Raleigh et al. 1976, Zoback & Haijes 1997). Donnelly (2009) reports on the mechanics of shallow depth fault reactivation associated with mining exploration and onshore fluid extraction activities. Large areas at surface may be affected, presenting evidences of subsidence and development of scarps.
Suckale (2010) presents data associated with induced seismicity around producing hydrocarbon fields and CO2 injection locations, associated with fault reactivation. Other examples do exist and certainly new cases will occur but the Groningen gas field, Sanz et al. (2015), is a good example of induced seismicity, caused by large hydrocarbon extraction that brought about the state government decision of reducing production in order to control the seismicity.
Within the European context, CO2 storage operations shall address the potential impacts of large scale CO2 storage through risk assessment. The key risks identified for this onshore CO2 storage site were the migration through faults and ground deformation.
To quantify the CO2 migration along a fault, flow modelling and uncertainties management codes are coupled to compute the failure probability i.e. the probability of CO2 migration towards a control aquifer. Such probability of failure is characterized by low to very low probability of occurrence which requires a large number of simulations to enable its evaluation. Each failure scenario models the CO2 migration from a storage aquifer to a control aquifer when altering the flow properties of the fault zone. Fault failure analyses are performed on the surrogate models. They show that limited CO2 migration is occurring along the fault but no breakthrough in the control aquifer. The injection induces some pressure disturbance in the control aquifer in about 30% of the cases which lead to effective stress changes.
To quantify effective stress changes due to CO2 injection and the subsequent ground deformation, the mechanical responses of the different sediment layers are modeled coupling flow and geomechanics. The impact of the stress changes on porosity and permeability of the storage reservoir is modeled along with the impact of uncertainties of the mechanical parameters. For this onshore CO2 storage site study case, the expected ground displacement is negligible (below the limit of the measurement capabilities).
In this article we present field results from two scale squeeze treatments carried out on the same subsea horizontal well from the Strathspey field in the North Sea. The initial squeeze was a bullhead application of phosphonate scale inhibitor to control a sulfate scale problem in a horizontal well. Ten months after the initial treatment a second bullhead squeeze treatment was applied in two stages. This latter utilized a thermally degraded pelleted wax diverter to temporarily impair the injectivity in the heel region of the horizontal well thus allowing propagation of the second stage of the squeeze treatment into the midsection of the horizontal well.
In this article we show the significance of production logging tool data to evaluate the location of deposited scale and water production prior to a squeeze treatment. These data were used to design a novel two stage squeeze treatment in which an initial squeeze slug was applied to the heel region followed by application of a pelleted thermally degraded wax diverter to prevent further loss of scale inhibitor to the heel region. The action of the wax diverter allowed a second scale inhibitor slug to be placed further along the horizontal section of the well. Details of the diverter selection and the squeeze design strategy implemented in this squeeze treatment will be presented. During the field treatment, physical (downhole pressure and temperature) data and chemical (nonradioactive tracers, inhibitor and ion concentrations) data were recorded. These data will be used to indicate the success of the diversion treatment by a comparison with the first squeeze applied to the same well 10 months previously.
This is the first successful application of a thermally degraded wax diverter to a subsea horizontal well in the North Sea basin. The well was successfully treated with no process upset during flowback and no decline in well production while allowing the well bore to be protected from continued sulfate scale formation. In this article it is clearly shown that with the correct selection of both the scale inhibitor and diverter agent together with ulitization of all available information relating to the reservoir, it is possible to squeeze scale inhibitors into subsea horizontal wells without the need for intervention by expensive coiled tubing from a diving support vessel.
The Strathspey field lies approximately 140 km northeast of the Shetland Islands in water 250 deep. The field consists of two reservoirs, the Statfjord, a gas condensate reservoir, and the Brent, a black oil reservoir.
Production is through a subsea manifold tied back by a network of pipelines to the Ninian Central platform. The manifold is 16 km in distance from the platform.
The Brent reservoir consists of a typical North Sea Brent sandstone sequence with several layered sand units on top of each other, each with a varying degree of vertical communication. The Brent reservoir is produced by seven wells with a further two wells providing water injection support. A map of the reservoir is presented in Fig. 1. The reservoir quality varies dramatically between sand units with permeabilities ranging from 100 to 1,000 md.
The Strathspey field has produced to date 52 MMbbl of oil and 110 Bcf of gas. Strathspey had produced at a plateau for four years and since 1997 the field has entered a production decline phase. The current field water cut is 76% with individual wells ranging from 64% to 90% water.
Four of the fields' seven producing wells are near horizontal producers and produce from several different pressured layers. The horizontal wells are capable of lifting between 10,000 and 35,000 bbl of fluid from the reservoir. This represents a large volume of water produced and often consists of both sea water and formation water produced from different layers within the reservoir.
A capacity for both barium sulfate scale and calcium carbonate scale exists within the fluids produced from the field. The desired method to prevent scale formation in both the near wellbore area and the tubing is squeezing. The squeeze process involves the introduction to the near wellbore area of a scale inhibitor which adsorbs to the formation and then returns slowly, providing protection against scale formation. The scale treatments described in this article are applied by a utilities pipeline 3.15 in. inner diameter (ID) that is bullheaded into the near wellbore formation. Typical injection rates are 4 bbl/min. The fluids are pumped using the resident cement unit on the Central platform.
This method of preventing scale deposition had proved successful in the vertical wells of this and other Texaco UK assets, however this method of application proved to be unsuccessful in horizontal, multilayered wells. Over a 1,000 BOPD was lost from a well as a result of scale buildup. This scale was removed from the tubing using a scale dissolver, however a new method of placing the inhibitor was required if this loss due to scale deposition was to be avoided.19
Formation Water Chemistry.
There are variations in the formation water chemistry in different wells within the field. This variation reflects the slightly different zones in which each well is completed. Typically the salinity of the formation water is 26,340 mg/L total dissolved solids (TDS) which is slightly lower than that of seawater. The barium and strontium levels within the pre-breakthrough seawater are in the range of 25 to 50 ppm barium and 20 to 30 ppm strontium, and 220 to 230 ppm calcium and 750 to 1,500 ppm bicarbonate. The maximum mass of barium sulfate scale is predicted to be deposited at a <5% seawater breakthrough, however the maximum mixed brine supersatuation is predicted to occur at about 50% seawater. A typical formation water analysis is presented in Table 1 . Carbonate scale formation is also expected based on the formation water composition and the operating temperature and pressure of the field and process systems. If uninhibited, production of a mixture of seawater/formation water will result in the deposition of sulfate scale. Carbonate scale is also probable when water is produced. The deposition of scale could occur in perforation tunnels or production tubing. Scale deposition will cause flow restrictions and possibly compromise the effectiveness of subsurface safety valves.
This paper presents field results from five scale squeeze treatments carried out on sub-sea horizontal wells from the Strathspey field in the North Sea.The development of a squeeze policy is outlined with the utilisation of laboratory coreflood data, computer simulation (SQUEEZE V Code) and the application of a novel solid divertor.
This paper outlines the practical difficulties in squeezing sub-sea horizontal wells and how some of the problems can be overcome.Some of the solutions that will be discussed include the use of variations in pump rates to encourage propagation of inhibitor along the well-bore, and the utilisation of fluid diversion techniques (both mechanical and chemical).The significance of production logging tool (PLT) data or good reservoir simulation data to evaluate the location of water production and any cross flow prior to a squeeze treatment design will also be stressed.Details of divertor selection, design simulation and the field results from the five squeeze design strategies that have been implemented will be presented.
From this series of field treatments it can be concluded that the wells have all been successfully treated with no process upset during flowback.No decline in the wells' productivity was observed as a result of these treatments.This paper shows that by using divertor agents, and by integrating near well-bore calculations (SQUEEZE V) and PLT/reservoir simulation data, it is possible to squeeze scale inhibitors into sub-sea horizontal wells without the need for coiled tubing intervention from a diving support vessel.
The Strathspey field lies approximately 140 km North East of the Shetland Islands in a water depth of 250 ft.The field consists of two reservoirs: the Statfjord, a gas condensate reservoir, and the Brent, a black oil reservoir.
Planning for the depressurization of the Brent Field required an extensive study of the aquifer to determine the withdrawals necessary to depressurize the field and to predict the effect of depressurization on surrounding fields. Static and dynamic aquifer models were constructed and several techniques were applied to evaluate the sealing capacity of the major boundary fault. Since the aquifer extends over several license blocks, integration of a wide range of data of varying quality from different sources was required to build up a complete aquifer model. The results highlighted effects of pressure communication between fields which were not apparent to teams studying individual fields in isolation.
Controlled depressurization of the Brent Field (Fig. 1) to maximize hydrocarbon recovery1,2 will require back production of considerable volumes of water to gradually reduce the reservoir pressure from 5500 to 1000 psi. An understanding of the size and strength of the aquifer attached to the reservoir (Fig. 2) is a critical input to the design of this process, influencing the rate and quantity of water to be back produced. In addition, other oil fields are thought to be in pressure communication with the Brent Field via the aquifer and the potential impact of Brent depressurization on all these fields needed to be quantified. Thus, as part of the planning for depressurization, an extensive integrated petroleum engineering study was undertaken to assess the range of uncertainties in the behavior of the Brent reservoir aquifer during depressurization and to quantify the possible impact of the redevelopment project on surrounding fields, including the effect of any possible communication between the Brent and Statfjord Fields.
This study was confined to the Brent reservoir as the Statfjord reservoir aquifer has already been shown to be relatively tight, with the result that depressurization will have minimal impact on even the nearest fields. In fact, the gas reserves in the Statfjord in both the Brent South and Strathspey Fields are planned to be produced by depletion drive, allowing the reservoir pressure to drop until the wells die, without any voidage replacement.
The investigation concentrated on three major aspects.
Extent and Properties of Brent Aquifer
Since there is a general dearth of data in areas between fields, the study required integration of a wide variety of data from various sources to produce an overall aquifer description.
Some base data were available from a limited series of time and reservoir property maps of the Brent and Statfjord Formations in the Greater Brent Area. These had been produced during an early review of the aquifer attached to the Statfjord Field. One initial task of the present study was thus to produce a depth map of the Brent Aquifer at top Brent reservoir level (Fig. 2). This was carried out by combining existing depth maps of known fields with a regional time map. The latter map was depth converted using available depth functions from the Brent Field itself, and tied in to all available wells within the aquifer. Over key areas, principally the Northern Boundary Fault area, all available seismic, both two dimensional (2D) and three dimensional (3D), was reevaluated to provide a consistent seismic interpretation.
A set of cross sections over the aquifer is shown in Fig. 3. To the north, west and east the Brent aquifer is seen to be bounded by major faulting. To the south, in the area of North Alwyn, the aquifer is effectively bounded by a combination of faulting and poor quality reservoir.
Historical Aquifer Pressure Data.
All available Brent reservoir pressure data from wells in the Greater Brent area were collated and corrected to the Brent Field datum level of 8700 ftss for comparison. The data consisted of repeat formation tests (or equivalent) pressure data from exploration, appraisal and early development wells (Fig. 4), together with average pressure trends from the fields on production. The early data from the 1970s suffered from inaccuracies in both absolute pressure measurements from Amerada gauges and in true-vertical depth conversion, since full deviation surveys were not run in supposedly vertical wells.
Representative average data were plotted against time for each cycle3 (Figs. 5 to 7), from which several conclusions were drawn:
This paper summarises the factors influencing the well design for a high pressure high temperature (HPHT) field development using a Not Normally Manned Installation (NNMI) in the UK sector of the Central North Sea (CNS).
The Erskine gas condensate field is a 50% Texaco / 50% BP venture and will be the first HPHT field developed in the North Sea with first gas scheduled for 1997 (Fig. 1). The field development concept is to install a not normally manned installation (NNMI) with multiphase export of produced fluids to the Lomond platform from six platform wells. Drilling and completion operations will be carried out using a harsh environment jack-up rig in cantilever mode.
Primary functional requirements for the wells include high reliability, high productivity and the ability to perform through tubing plug-backs. Reserves in the core area are found in three separate but generally overlying Jurassic sandstone producing horizons, the Kimeridge, Erskine, and Pentland sands.
A multi-discipline project team consisting of reservoir, production, drilling and facilities engineers was set up to progress the development concept. Specific well design principles were adopted and an iterative approach was used to produce a robust and reliable drilling and completion design that is compatible with the overall development concept and provides reliability on a NNMI in HPHT service conditions.
Jackup drilling will commence over the platform jacket which will be installed over an existing sub-sea appraisal well in the spring of 1996 (Fig. 2). Two wells will be predrilled through the jacket structure and suspended prior to the platform topsides deck being lifted into place in 1997. The appraisal well will be tied back and wells will then be completed ready for commercial gas export in late 1997. Further wells will then be drilled and completed as required.
Platform Concept Outline
By North Sea standards Erskine is a marginal field (335 MMSCF gas, 66.5 MMBBL oil). The resultant development has revolved around this in order to make development economic. The following lists the main features of the development.
1) Simple NNMI 12 slot wellhead platform providing unprocessed multiphase fluids export to host platform with a projected field life of 15-20 years.
2) Platform design and slot layout which enables access to all slots for cantilevered jack-up drilling in the 300 ft water depth.
Well Design Considerations
Primary considerations for the well design are:
1) Reservoir fluids containing H2S and CO2. Reservoir pressure +/-l4,000 psi, temperature 350 F, initial surface shut-in pressure 10,600 psi (Table 1).
2) Design flow rates required from each well will be up to 60 mmscf/day of gas.
3) The wells that are initially completed as Pentland sand producers will water out and require to be plugged back and recompleted as Erskine sand producers. Due to availability and cost of large jack-up rigs, this requires to be a rig-less operation.
The Ninian partners have developed an innovative commercial framework which will apply to a number of future satellites, dispensing with the often lengthy and complicated process required to develop individual terms for each satellite. The new style agreement promotes the concept of future satellites sharing the Ninian platform topside facilities for processing, metering and export, as well as platform drilling instead of more costly subsea wells where appropriate. This enables potential satellites to be developed simply quickly and economically.
In the formative years of the UKCS oil & gas industry, fields were only developed if of sufficient size to justify the huge capital expenditure to install all the infrastructure required to get the oil and gas produced to the markets. Such infrastructure included not only the production platforms, but also pipelines to shore, as well as the onshore treatment and export facilities.
Twenty years on, many giant and medium sized fields have been developed, and a significant infrastructure in the North Sea now exists. This, combined with technological innovations, has been essential in allowing smaller accumulations to be developed as subsea satellites tied back to a host platform, which provides the processing and export facilities. The growth in satellite developments has been greatest where the satellite operator and/or unit owners have been the same as for the host facility, with the result of retaining the economic benefit within the same partnership.
In 1990, the Ninian Field Group reached agreement with the Lyell Field Group, operated by Conoco, for Ninian to act as a host facility for a Lyell subsea development. This represented one of the first in the North Sea, where the satellite field and the host facility were not owned and operated by the same parties. Subsequently agreements were reached with LASMO and Texaco as operators of the Staffa and Strathspey fields for Ninian to act as host facility for these fields which are also subsea developments. In 1994 these three fields are anticipated to produce a combined 60 mstb/d of oil and LPG and 100 mmscf/d of gas, compared with Ninian production of 60 mstb/d.
The Ninian Field Group is therefore currently party to three separate processing tariff arrangements, as well as its involvement in the Ninian Pipeline System and Sullom Voe Terminal.