Enoco (Norway)

Abstract In the Valhall field in the North Sea, significant resources have been identified in the flanks of the field. In this situation the reservoir targets are the main driver for the wellbore trajectory planning. Even if all of the traditional drilling parameters have been addressed and the well can be drilled on paper, the wellbore can experience wellbore stability problems (lost circulation, stuck pipe, tight hole). These wellbore problems can gradually progress or suddenly occur. The problems may be aggravated by mud properties or mechanical interaction between the rock and the drilling assembly. Wellbore stability models, using offset drilling information, indicated early in the planning process at Valhall that the drilling of extended reach wells in the field was going to be a challenge. This challenge is the result of a narrow safe operational mud pressure window that narrows progressively with increasing wellbore sail angle. This theoretical window upper bound is given by lost circulation. The lower bound is given by the onset of wellbore collapse. This narrow window leaves hardly any room for the surge and swab pressures associated with pipe movement and pump changes. The flank locations require sail angles close to 75 degrees in the overpressured unconsolidated claystone of Tertiary age. The record well to date had a build and hold trajectory at 74 degrees. On this record well around 3 MM USD was spent on fighting wellbore stability problems (around 750 hours). Since traditional wellbore stability analyses have already indicated a high risk of instability, and some wells have been successful, while others not, consideration was given to developing new tools to assist in the well planning in the overburden. We wanted to look at potential heterogeneous rock strength changes that could not be picked up using offset well information in the planning. The approach was to develop a more detailed geological model for the overburden with geologic formation top surfaces and 3D seismic coherency data. In this 3D data cube the drilling problems encountered on the offset wells were correlated along the wellbores. The 3D data presentation was done in a standard visualization software (GEOVIZ). The paper will present the geomechanical theory behind wellbore stability problems in faultzones and fractured rock mass, how the geologic model has been developed and how the visualization software is used to select a wellbore trajectory with the lowest risk of wellbore instability problems. Several case histories are included to illustrates the potential this methodology has for reducing unscheduled events due to wellbore instability problems while drilling the wellbore from the seafloor to the reservoir. Potential for further improvement is highlighted

Abstract Oil production from this chalk field has been improved significantly over the last three years through the use of multiple proppant fractures placed from horizontal completions. Following early successes the engineering effort now focuses on increasing value through engineering innovation and increased productivity. This paper describes, through case histories and field data, the advances made in the design and execution of these completions over the first 13 such wells in the field. Wellbore completion activities and stimulation are now performed as a standalone process through the use of specialized large diameter coil tubing equipment so allowing on-going drilling operations to be performed concurrently. This has significantly reduced daily spread costs while bringing wells on production within a much reduced time frame. This lower cost environment has also allowed innovative field procedures to be developed resulting in further improvements such as proppant plugs for isolation between stimulation zones and treatments using recycled proppant to minimize waste. Treatment design has been refined through downhole pressure monitoring which has allowed empirical frictional relationships to be developed for proppant slurry and coil tubing circulating fluids. This data validates the wellbore tubulars design and allows any weak points in the arrangement to be highlighted for change. An extensive fracturing database is maintained allowing each treatment design to be compared with previous experience in the field. Productivity is the driver for economic success and treatment design requirements have evolved through laboratory testing to account for longer term downhole operating conditions below the bubble point while also improving initial conductivity. Field data to date through PLT logging has confirmed the hydrocarbon contribution from each fracture and this is used to validate, or otherwise, the effectiveness of each treatment. Normalized well productivities continue to improve and the challenge is to maintain the rate of evolution through the improved application of both new and existing technologies. P. 335

Abstract Oil production from horizontal wellbores in the Valhall field has often proved both unstable and below expectation in this soft chalk formation. Multiple acid etched fractures from such wellbores have yielded encouraging results but exhibit limited longevity due to compaction. This paper describes the integration of proppant fracturing and horizontal well technology to provide a long term cost effective solution and so yield both high and sustained production in this field. A numerical model was calibrated against known production profiles for both existing horizontal wells and conventional proppant fractured wells in the field. This was then configured to determine the production decline rates for various multiple proppant fractured horizontal completions operating under a standardized drawdown schedule. This indicated the number, size and conductivity of proppant fractures to provide an optimum risk weighted economic return. Convergent flow pressure drop was evaluated using a derivation of the Forcheimer Equation to allow radial flow to be analyzed. Proppant pack conductivity testing was performed under specific reservoir conditions of placement, stress, temperature and flowback while also using an optimized carrier gel and breaker concentration. New resin coated ceramic proppant were benchmarked and a selection made with due consideration for conductivity and pack strength under convergent flow conditions. Using these results the required fracture conductivity was developed using tip screen out (TSO) methods to maximize propped fracture width and offset embedment into the soft chalk. A specific methodology was followed for the perforating, fracturing, cleanout and isolation of each production zone. Individual fracture productivity has been determined by flowing the well for an extended period following each treatment. As expected, the productivity index doubled following the second treatment, however the third treatment yielded only a marginal increase in overall productivity. A number of possible causes have been investigated. Benefits from integrating horizontal well and proppant fracturing technology are illustrated by the post completion economic analysis. This indicates, that despite the increased cost of the completion, the payout time is 15% sooner, with a rate of cash return 100% greater, than that of the average horizontal well in the field. The process has now been further improved since this pilot project was placed on stream. Completion costs, and execution time, have reduced significantly through the use of large size coil tubing in a revised wellbore design. This has further allowed the completion phase, as described in this paper, to be performed as a concurrent activity entirely off rig time. Introduction The Valhall Field is an Upper Cretaceous, asymmetric chalk anticline which forms an overpressured, under saturated, oil reservoir located in the Norwegian sector of the North Sea. It is characterized by high porosity (25-48%) and high oil saturation (92-97%) and, in common with other chalk reservoirs in the region, the drive mechanism is a combination of fluid expansion and formation compaction. The production is mainly drawn from the high porosity (35-48%) Tor formation which exhibits a typical thickness of 80–100 ft and a permeability of 1–10 mD. In some parts of the field the underlaying, lower porosity (25-35%), Hod formation is also productive with a permeability of 0.5–2 mD. The source rock for this hydrocarbon deposit is the organically rich Kimmeridgian Clay underlaying the chalk. This has resulted in a reservoir which is over pressured for depth with a undepleted gradient of 0.80 psi/ft TVD at 8200 ft TVD, Ref 1. The field originally held estimated reserves of 585 MMSTB and currently produces at 80,000 BOPD from 30 wells. P. 241

ABSTRACT Pore and fracture pressure determinations are key considerations for the successful planning and drilling of North Sea Central Graben High Pressure High Temperature (HPHT) wells. Knowledge of these downhole pressure constraints can have a significant impact on drilling safety and economics. In this paper we present recent advancements to a previously presented methodology. Pore and fracture pressure is determined using wireline or MWD petrophysical data and an effective stress approach. The results have increased our understanding of overpressure generation mechanisms and hydrocarbon migration in this basin. Most traditional pore pressure estimation methods use a shale disequilibrium compaction model for their calculations. We assess these methods and propose that excellent results can be obtained by deriving porosity from density or deep resistivity data. This porosity, together with a lithology estimation from the gamma ray, are input into an Effective Stress Loading limb (ESL) model that calculates pore and fracture pressures through all major lithologies. Along the North Sea Central Graben axis there are two distinct pressure domains. These are separated by a low porosity (<5%) horizontal pressure seal within the Cretaceous Chalk Group. This seal occurs between ~3.5-4km and is independent of stratigraphic level within the chalk. Above ~3.5km, rapidly deposited Tertiary shales and Upper Cretaceous chalks are on the compactional loading limb. Here, moderate overpressures are generated by disequilibrium compaction. Below ~4km, low porosity (5-10%) Mesozoic sediments are unloaded by fluid expansion mechanisms to produce extreme overpressures. The upper limit for the pore pressure is the fracture propagation pressure. When this is exceeded, hydraulic fracturing can occur and the fluids escape, allowing the fracture to close and pressure to build again. In this environment, primary hydrocarbon migration may be largely dependent on the rate of the hydraulic fracturing formed as a consequence of the extreme fluid pressures generated by fluid expansion. An understanding of these pressure generating mechanisms, together with improved porosity determinations, has led to more accurate pore and fracture pressure determinations. Implementing the results into well planning and drilling can help avoid many of the costly pressure related problems inherent to HPHT wells.

Risk Analysis of Well Performance: A New Approach To Optimize Well Deliverability Liv Johannessen; Liv Johannessen Conoco Norway Inc. Search for other works by this author on: This Site Google Scholar Hilde Bakken Hilde Bakken Norsk Hydro A/S Search for other works by this author on: This Site Google Scholar Paper presented at the European Production Operations Conference and Exhibition, Aberdeen, United Kingdom, March 1994. Paper Number: SPE-27594-MS https://doi.org/10.2118/27594-MS Published: March 15 1994 Cite View This Citation Add to Citation Manager Share Icon Share Twitter LinkedIn Get Permissions Search Site Citation Johannessen, Liv, and Hilde Bakken. "Risk Analysis of Well Performance: A New Approach To Optimize Well Deliverability." Paper presented at the European Production Operations Conference and Exhibition, Aberdeen, United Kingdom, March 1994. doi: https://doi.org/10.2118/27594-MS Download citation file: Ris (Zotero) Reference Manager EasyBib Bookends Mendeley Papers EndNote RefWorks BibTex Search Dropdown Menu nav search search input Search input auto suggest search filter All ContentAll ProceedingsSociety of Petroleum Engineers (SPE)SPE European Production Operations Conference and Exhibition Search Advanced Search SPE MembersAbstractThe Heidrun field, situated on the Norwegian Continental Shelf (Figure 1), is scheduled to come on stream in August 1995. Heidrun will be developed using a tension leg platform (TLP). The reserves are estimated to 119 M Sm3 (750 M STB) of oil and 45 GSm3 (1.6 TSCF) of gas. Heidrun consists of three main reservoirs, the Fangst Group, the Tilje Formation and the Are Formation where the Fangst Group contributes more than 70% of the total reserves. A total of seven Fangst oil producers will be pre-drilled and pre-completed to accelerate the build up period. These wells are all planned as gravel packed wells with high deliverability.To optimize the completion design and maximize flowrate potential for the producers, a new approach to evaluate well performance was developed. The individual well deliverabilities were computed as a probability distribution directly reflecting the uncertainties related to the input variables rather than the more conventional single flow rate.The results showed that the flowrate was likely to be restricted by the completion configuration rather than the reservoir deliverability. As a result, the current tubing size was increased and the Fangst well design rate was raised. By increasing the design rate, the pre-plateau period was reduced. This increased the NPV of the Heidrun project significantly.IntroductionNodal analysis is a proven technique to predict well deliverability, among others used for input into reservoir simulators and for completion design to suit the individual well performance.The quality of the analysis is of course heavily dependent on the quality of the input data. In fields in the pre-development phase which do not have any dynamic data available, the uncertainties in the completion input parameters become more critical. Gravel packed wells introduce yet another set of input parameters which are often difficult to define. On Heidrun this was of particular concern since seven oil producers would be pre-completed and gravel packed before production start up. A new method which quantified the uncertainty in the resulting flow rate was developed to solve the problem.P. 57^ Keywords: thickness, drillstem testing, upstream oil & gas, well capacity, machine learning, flow rate, probability distribution, risk analysis, completion installation and operations, regression equation Subjects: Formation Evaluation & Management, Perforating, Drillstem/well testing, Well performance, inflow performance, Completion Installation and Operations, Completion Operations This content is only available via PDF. 1994. Society of Petroleum Engineers You can access this article if you purchase or spend a download.

Summary This paper discusses the execution, analysis, and results of an unconventional waterflood pilot in a major, naturally fractured chalk, oil reservoir in the North Sea. Pilot operation above formation parting pressure (FPP) solved the low-injectivity problem but required use of new and innovative techniques to interpret and to predict pilot behavior properly.

ABSTRACT Development drilling at the Heidrun field offshore mid-Norway is currently underway. The Heidrun field will be developed with a concrete hull Tension Leg Platform (TLP) in 345 meters (1132 feet) of water1,2. The pre-drilling program to be conducted from a semi-submersible includes drilling and partially completing nine wells, setting 30" conductor and 22" surface liners in the remaining 47 TLP-template well slots and drilling and completing 6 water injection wells in two remote subsea templates. This paper will review the extensive planning as part of the overall Heidrun project and present a review of drilling operations to date. The state of the art drilling techniques being implemented to overcome unique drilling problems and complete the substantial scope of work will be described.

Summary This paper presents the development of a multiphase pressure-transient-analysis technique for naturally fractured reservoirs and the analysis of a series of field tests performed to evaluate the water injection potential and the reservoir characteristics of a naturally fractured reservoir. These included step-rate, water-injectivity, pressure-falloff, and flowback tests. Through these tests, a description of the reservoir was obtained.

Two computer programs have been developed to model maturation parameters. The first program (referred to as K-MOD) relates thermal conductivity to interval velocity and then computes either geothermal gradient or heat flow, depending on which is known. The program can be run using interval velocities obtained from either well or seismic data. The second program (referred to as M-MOD) is a maturation modelling program based on time—temperature, theoretical kinetic equations. M-MOD requires burial history, interval geothermal gradients and unconformity data as input. The program then computes present-day equivalent vitrinite reflectance (R e ) values for up to 21 horizons along with palaeo-temperature, palaeo-depth and palaeo-R e values for designated time-stratigraphic horizons.

Abstract Problems encountered in drilling Tertiary clays and shales in the southern part of the Norwegian Continental Shelf and the mud system most frequently used in this area, are reviewed in this paper. Severe viscosity problems frequently arise while drilling the top 10,000 feet of hole, which predominantly consists of clays and shales, and are the direct cause of several problems like swabbing formation; blocking of flowlines and shaker screens by very soft sticky clay; sticking of drill pipe; and bit and collar balling. The viscosity problems are the result of lack of solids removal equipment, the dispersing type drilling fluid used which makes the solid separation more difficult, and the facts that the lower 5,000 feet of formation is overpressured, behaves plastically, and has a high montmorillonite content. A salt solution base mud is discussed as an alternative to the commonly used lignosulfonate system. Hydration tests of formation samples in various salt solutions indicate that low density solid content in the drilling fluid might be controlled more economically by the use of a salt water base mud and centrifuges and fine screen shakers. To date mud properties have partially been controlled in the unsatisfactory manner of discarding old mud and making up new mud. It is concluded that a saving of 25% on the cost of barite alone seems possible with a salt solution base mud. possible with a salt solution base mud. More important however, are the potentials for reducing rig time and potentials for reducing rig time and consequently cost. Introduction This study presents mud programs and drilling problems pertaining to the Tertiary clays and shales in the southern part of the Norwegian Continental Shelf (see Fig. I).