Proppant fractures along the horizontal laterals in the Valhall Field have become a standard completion method for the last eight years with over 150 proppant fractures completed to date. The development of the flank regions of the Valhall Field began, with the first of 14 wells completions, in March 2003. Lateral lengths of up 2,000 meters will be drilled from two new platforms placed on the North and South edges of the field. The chalk formation in the flank regions is expected to be more competent then the crestal part of the field, so the question was raised as to whether fracturing should be done with acid or proppant. From a proppant fracturing perspective, each flank well will require between 10 to 14 prop fractures along its lateral requiring 2.5–3.7 Million pounds of proppant per well. Three different methods have been used to determine whether the wells should be acid or proppant fractured. These consist of reviewing the historical well performance, analytical and numerical modeling. All three methods clearly showed proppant fracturing was the preferred stimulation for the Valhall Field regardless of it's location. Acid fracturing becomes the stimulation of choice only if the well does not come in contact with enough OOIP (e.g. 5 MMSTB) to justify the proppant fractures. Proppant fracturing is expensive, so in conjunction with identifying the best stimulation method for the flank region, optimization with respect to fracture spacing along the horizontal lateral, fracture length and width have been numerically modeled for both the crestal and flank wells. This is an evolving process that should be considered an industry "Best Practice" as it enables real time optimization of ‘prop’ fracturing along a horizontal lateral during the drilling and completion phase. Since the start of this "Best Practice" in 2002, the wells stimulated in the crestal part of the Valhall Field have had the highest productivity in the field's history. Introduction The Valhall Field is an Upper Cretaceous, asymmetric chalk anticline that forms an overpressured, under-saturated, oil reservoir located in the Norwegian sector of the North Sea (Figure-1). It is characterized by high porosity (25–48%) and high oil saturation (92–97%). 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 from the high porosity (35–48%) Tor formation, which exhibits typical thickness of 15–40 m and a permeability of 1–10 mD. The source rock is the organically rich Kimmeridigian Clay underlying the chalk and has resulted in a reservoir, which is over pressured for depth with an undepleted gradient of 0.78 psi/ft TD at 2,500 mTVD1. The field will recover over 1 billion STB with current production of 80,000 BOPD from 42 wells on the main Drilling Platform and the Wellhead Platform (WP), which are centrally located in the crestal part of the field. The field was originally sanctioned and placed on production back in 1982 with reserve estimates of only 250 MMSTB. Reserves have increased by 400% since then throughbetter reservoir description,improving the completions and drilling strategy from vertical indirect proppant fractures to long horizontals with multiple proppant fractures, andthe current development of the flank areas of the field and the initiation of a waterflood in the crestal section.
Valhall, an offshore field in Norway, is a black oil reservoir producing mainly through multi-fractured (with proppant) horizontal wells.1 The bottom hole flowing pressure is well below the bubble point and hence the fracture conductivity is significantly constrained by multiphase non-Darcy pressure drop losses. Geertsma in 1974 was the first to propose a multiphase Beta (non-Darcy constant) correlation as a function of permeability, porosity (size) and saturation. Recent testing to measure the non-Darcy pressure drop for multiphase flow in proppant packs was successful in verifying a strong relationship to saturation. Three different types of 16/20 proppants with three different resins and one of 12/18 and 20/40 were tested (total of eleven samples) in a conductivity cell under field conditions (temperature of 195 deg F and 1,500–6,500 psi confining stress), for a proppant loading of 4 Lb/ft2. The proppant was placed in the cell using a 30 lb crosslink borate X-link fluid with 4 ppt (lbs/1000 gal gel) of encapsulated breaker for 24 hours to allow fluid break prior to conducting the flow tests. The Geertsma type equation was used to match the laboratory data. The equation constants (for permeability, porosity and saturation) for each proppant/resin type were derived. The non-Darcy correlations for each proppant were used in a numerical simulator to determine the pressure drop in the fracture and to quantify the effects on production rates. The paper highlights the importance of proppant size for optimizing fracture design for wells producing under multiphase flow. Introduction A study was commissioned by BP Norway to assess the effects of various proppant sizes, resins and types on productivity under field conditions. The study contained three parts as follows:Single phase gas flow laboratory tests were performed under ambient conditions to evaluate the validity of the Forchheimer equation under very high rates.Single and two-phase flow (gas and water) laboratory tests were conducted to measure the Beta factors at field conditions with stresses between 1,000 and 6,500 psi and a temperature of 195 F.The multiphase Beta factors for 20/40, 16/20 and 12/18 proppant were then imported into a numerical model and the production was compared. The study indicated only slight difference between the various 16/20 ceramic proppants. The higher density ceramic resin coated proppant indicated less cumulative production mainly due to its higher density and hence lower fracture width for the same proppant concentration of 4 Lb/ft2. On the other hand, the results for two light weight ceramics with the three-tested resins were close. 12/18 ceramic proppant with a high bonding strength dual coated resin results was also compared to 16/20 and 20/40 proppant with the same resign. The results indicate some 25% and 56% more cumulative production after 400 days for the larger proppant, in comparison to 16/20 and 20/40, respectively. Hence, a substantial upside lies in utilizing 12/18 proppants or larger, particularly in depleted areas where the reservoir pressure is close to the bubble point estimated at 3,350 psi. Background Non-Darcy Equation Henry Darcy initially developed his famous correlation by observing water draining through a sand column. Essentially, he conducted his experiments by placing water on top of a sand column and timing how long it took for the water to trickle through the sand. The fluid velocity was very low and Darcy's studies showed that at these velocities, the pressure drop through a porous media is proportional to the fluid velocity.
Having completed both fracture treatments as discussed in a companion paper, this paper continues on to describe the post fracture shut-in, clean-up and well testing operations that took place on the Viking Wx exploration well 49/17-12. These operations involved the removal of Resin Coated Proppant (RCP) from the wellbore, via Coiled Tubing (CT), through the use of a specially designed jetting nozzle. The RCP pack stability at a concentration of 3.0 lb/ft2 (as per planned design) had already been tested in a flowback cell. The use of a Surface Read-Out (SRO) gauge, combined with gas, water and proppant flow rates as well as the viscosity of fracturing fluids returns, enabled real time calculation of the drag forces, on the proppant pack, during clean-up. The flow rate, in the field, was controlled such that the calculated drag forces remained below those observed in the laboratory. Following the clean-up a flow and build-up test was conducted, to evaluate the fracture half length and fracture conductivity, from which a Pseudo-radial skin was calculated. The Non-Darcy effects in the fracture were also evaluated, and finally the short term and long term well deliverabilities were assessed. Introduction The Viking Wx formation is located in block 49/17-12 within the V-fields area of the Southern North Sea (SNS). When first drilled, during late November 1994, the well encountered an 830.0 ft thick Rotliegendes sandstone. However Drill Stem Test (DST) results were disappointing, with rates of only ca. 8.5 MM.scf/d, and as completed the development was not economic. Shortly after this DST test Conoco and BPX formed a fracturing team to investigate the possibility of achieving economic rates for the development via stimulation. The well was fracture stimulated in April 1995 when two stacked treatments were performed. A total of 830,000 lbs of 20/40 Intermediate Strength ceramic Proppant (ISP) was successfully placed. The RCP utilised a dual-coat curable phenolic resin with low-reactivity outer coating and fully cured inner coating. The companion paper, to this one, describes both of these fracture treatment implementations in detail. Once the second fracture treatment had been completed the well was shut-in for 28 hours, to allow the RCP to cure. Subsequently 2" CT, with a jetting nozzle, was then rigged up and Run In Hole (RIH) to remove the excess RCP material from the 7" liner. The well was then flowed for four and half days to clean-up the load fluid. The flow rate at the end of this cleanup period was ca. 43.5 MM.scf/d and 215 bwpd. A second CT run was made, followed by a spinner survey and a 180 hr flow and build-up test. Slick line was then RIH and tagged bottom indicating no proppant flow during the well test. The well was then suspended and is currently awaiting field development plans. Laboratory Tests The following Section outlines the laboratory tests that were conducted prior to the fracture treatment to help determine allowable drag forces on the proppant pack. A flowback test was conducted at anticipated bottom hole flowing conditions to evaluate the turbulence factor, Beta, in 20/40 ISP partially curable RCP and broken fracturing gel. The methodology is based around the Forchheimer equation. (1) The above equation can be re-arranged to, (2) P. 587
This paper describes the implementation of a twin propped fracture stimulation treatment, carried out on (he 49/17-12 exploration well of the Viking Wx structure, in the Southern North Sea (SNS). Initial appraisal of the potential field development was disappointing, the well flowing at a rate of only 8.5 MM. scf/d, indicating a field development to he uneconomic. Stimulation by a joint Conoco/BPX team, employing novel fracturing technology, provided dramatic increases in production to ca. 43.5 MM. scf/d with less applied drawdown. The design approaches employed during these treatments could have potential for widespread application [o other SNS gas fields, In this paper critical pre-treatment testing and reasoning behind operational decisions are discussed. In a companion paperl the post stimulation rates/testing and well clean-up are described. Several key aspects of these treatments included: the use of two stacked fractures in order [o successfully place proppant across the entire 830 ft reservoir section; the use of a Step Down Test (SDT) to identify the nature of high near wellbore pressure losses and subsequent removal using sand slugs; the use of's newly developed dual-coat partially curable Resin Coated Proppant (RCP) product, never previously utilised in the field, to minimise the opportunity for prolonged proppant back production and a seawaler Mini-Frac to attempt to help identify the true in-situ permeability. Finally, the use of a Surface Read-Out (SRO) gauge enabled real-time decision making to optimise the treatment schedule.
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